WM 19-0008, Financial Assurance Requirements for Decommissioning Nuclear Power Reactors 10 CFR 50.75(f)(1): Difference between revisions
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3,317 748 829 0 254,848 151,541 87,071 16,236 A umohons re* Rates/Factors soeclflc to Owner and Jurisdiction cbst Escalation Rate Prior Current Prior Current Prior Current obtained from KCC Docket 15-WCNE-093-GIE 18-WCNE-107-GIE 15-WCNE-093-GIE 18-WCNE-107-GIE 15-WCNE-093-GIE '18-WCNE-107-GIE 3.15% 2.91% 3.15% 2.91% 3.15% 2.91% | 3,317 748 829 0 254,848 151,541 87,071 16,236 A umohons re* Rates/Factors soeclflc to Owner and Jurisdiction cbst Escalation Rate Prior Current Prior Current Prior Current obtained from KCC Docket 15-WCNE-093-GIE 18-WCNE-107-GIE 15-WCNE-093-GIE 18-WCNE-107-GIE 15-WCNE-093-GIE '18-WCNE-107-GIE 3.15% 2.91% 3.15% 2.91% 3.15% 2.91% | ||
oltained from MPSC Docket E0-2018-0062 E0-2018-0062 N/A N/A 3.16% 3.1,6% NIA NIA Aner Tax Earnings on Funds | oltained from MPSC Docket E0-2018-0062 E0-2018-0062 N/A N/A 3.16% 3.1,6% NIA NIA Aner Tax Earnings on Funds | ||
!Kansas | !Kansas | ||
* From KCC Docket 1B-KCPE-480-RTS 2012- 2025 5.60% TBD 2012 -2025 5.84% 2018-2084 4.62% 2012 -2025 6.74% TBD 2026-2035 4.83% TBD 2026 - 2045 deer - .25%/year 2085 -2091 3.95% | * From KCC Docket 1B-KCPE-480-RTS 2012- 2025 5.60% TBD 2012 -2025 5.84% 2018-2084 4.62% 2012 -2025 6.74% TBD 2026-2035 4.83% TBD 2026 - 2045 deer - .25%/year 2085 -2091 3.95% | ||
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obtained by multiplying the unit price by the number of shares/units as Capital Gain / (Loss) Sections: The information contained in this of the statement date. The market value of a security , including those section(s) includes a gain or a loss summary of your account and is priced at par value , may differ fro m its purchase price and may not not a solic itation or a reco mmendatio n to buy or sell. It may however, closely reflect the value at which the security may be sold or be helpful for investment and tax planning strategies. It should not be purchased based on various market factors. relied upon for filing your tax return as it may not include all taxable transactions. UMB has provided cost basis information wherever | obtained by multiplying the unit price by the number of shares/units as Capital Gain / (Loss) Sections: The information contained in this of the statement date. The market value of a security , including those section(s) includes a gain or a loss summary of your account and is priced at par value , may differ fro m its purchase price and may not not a solic itation or a reco mmendatio n to buy or sell. It may however, closely reflect the value at which the security may be sold or be helpful for investment and tax planning strategies. It should not be purchased based on various market factors. relied upon for filing your tax return as it may not include all taxable transactions. UMB has provided cost basis information wherever | ||
UMB Account Name: KANSAS GAS & ELECTRIC WOLF CREEK GENERATING STATION DECOM TRUST Account Number: 116889 Statement Period : Dec. 1 - Dec. 31, 2018 Page 3 of 7 Market Overview Asset Allocation Current Period Year-to-Date 12/01/2018 01/01/2018 Beginning Market Value 238,187,826.57 237 I 102,282,59 Income Dividends 94.86 5,159,589 .64 Other Income 97 ,394.16 893 ,632.07 Net Contributions/Distributions Receipts 97,488.53 14,086,898 .23 Disbursements (97,488.53) (9,478,868 .35) Account Value | UMB Account Name: KANSAS GAS & ELECTRIC WOLF CREEK GENERATING STATION DECOM TRUST Account Number: 116889 Statement Period : Dec. 1 - Dec. 31, 2018 Page 3 of 7 Market Overview Asset Allocation Current Period Year-to-Date 12/01/2018 01/01/2018 Beginning Market Value 238,187,826.57 237 I 102,282,59 Income Dividends 94.86 5,159,589 .64 Other Income 97 ,394.16 893 ,632.07 Net Contributions/Distributions Receipts 97,488.53 14,086,898 .23 Disbursements (97,488.53) (9,478,868 .35) Account Value Expenses/Fees (6,863,692.42) Percentage Market Value Capital Gain Distributions Equity Funds 53% $119,800,451 Change in Market Value (1 0,823 ,154. 69) (13,437,680.86) Fixed Income Funds 29% $64,923,859 Ending Market Value 227 ,462,160.90 227 ,462,160.90 | ||
* Real Estate / Oil & Gas Unique Assets 17% | * Real Estate / Oil & Gas Unique Assets 17% | ||
1% $3,241,109 | 1% $3,241,109 | ||
| Line 290: | Line 288: | ||
methodology reliant on unsubstantiated speculation, the Commission prefers a *methodology that has been endorsed by the Nuclear Regulatory Commission (NRC). | methodology reliant on unsubstantiated speculation, the Commission prefers a *methodology that has been endorsed by the Nuclear Regulatory Commission (NRC). | ||
: 15. In 1988, the NRC announced decommissioning requirements for licensed nuclear power facilities. 43 The NRC defined three acceptable decommissioning alternatives: (1) DECON, (2) SAFSTOR, and (3) ENTOMB. Under DECON, portions of a facility and site containing | : 15. In 1988, the NRC announced decommissioning requirements for licensed nuclear power facilities. 43 The NRC defined three acceptable decommissioning alternatives: (1) DECON, (2) SAFSTOR, and (3) ENTOMB. Under DECON, portions of a facility and site containing radioactive contaminants are removed or decontaminated to a level where the property can be used without restriction after the plant closes. 44 Under SAFSTOR, the nuclear facility is safely stored and decontaminated to a level where the property can be used without restriction within 60 years. 45 Under ENTOMB, radioactive contaminants are encased in concrete until the radioactive material decays to a level permitting unrestricted use of the property. 46 In March 2017, the NRC staff proposed removing the ENTOMB option from existing guidance documents, deeming. it impracticable. 47 None of the parties advocate for the ENTOMB method. As there is no evidence in the record to support the ENTOMB method, the Commission will not consider it as a viable option. | ||
radioactive contaminants are removed or decontaminated to a level where the property can be used without restriction after the plant closes. 44 Under SAFSTOR, the nuclear facility is safely stored and decontaminated to a level where the property can be used without restriction within 60 years. 45 | |||
Under ENTOMB, radioactive contaminants are encased in concrete until the radioactive material decays to a level permitting unrestricted use of the property. 46 In March 2017, the NRC staff proposed removing the ENTOMB option from existing guidance documents, deeming. it impracticable. 47 None of the parties advocate for the ENTOMB method. As there is no evidence in the record to support the ENTOMB method, the Commission will not consider it as a viable option. | |||
: 16. Since 1989, the NRC's Information Digest indicates eighteen reactors have been shut down. 48 DECON was the decommissioning alternative selected for nine of those reactors, SAFSTOR was selected for five, and the remaining four were initially placed in safe-storage before switching to DECON. 49\,_ In choosing between DECON and SAFSTOR, the Commission believes it would be extremely irresponsible to select a methodology that assumes the federal government will be able to accept the spent fuel at the time of decommissioning. There is no evidence that the 43 Study Attachment 2, p. 8 of 139. | : 16. Since 1989, the NRC's Information Digest indicates eighteen reactors have been shut down. 48 DECON was the decommissioning alternative selected for nine of those reactors, SAFSTOR was selected for five, and the remaining four were initially placed in safe-storage before switching to DECON. 49\,_ In choosing between DECON and SAFSTOR, the Commission believes it would be extremely irresponsible to select a methodology that assumes the federal government will be able to accept the spent fuel at the time of decommissioning. There is no evidence that the 43 Study Attachment 2, p. 8 of 139. | ||
44 Id. | 44 Id. | ||
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BY THE COMMISSION IT IS SO ORDERED. | BY THE COMMISSION IT IS SO ORDERED. | ||
Albrecht, Chair; Emler, Commissioner; Keen, Commissioner 08/02/2018 Dated: - - - - - - - - - - | Albrecht, Chair; Emler, Commissioner; Keen, Commissioner 08/02/2018 Dated: - - - - - - - - - - | ||
~ | ~ | ||
~ | ~ | ||
L1 * ~r-* | L1 * ~r-* | ||
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3 | 3 | ||
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 Q. What amount did KCP&L propose for its Kansas NDT annual accrual? | Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 Q. What amount did KCP&L propose for its Kansas NDT annual accrual? | ||
2 A. KCP&L proposed to keep its NDT annual accrual unchanged at $2,036,230 as set in the 3 previous review in Docket No. 15--KCPE-116-RTS. This position is KCP&L's adjustment 4 CS-37 sponsored by Ronald Klote./ KCP&L filed this position prior to the Co:mrtlission's 5 decision in 18-107. We now have the 18-107 Order which selected the SAFESTOR 6 decommissioning methodology which is lengthier and more expensive than the 7 decommissioning 1, | 2 A. KCP&L proposed to keep its NDT annual accrual unchanged at $2,036,230 as set in the 3 previous review in Docket No. 15--KCPE-116-RTS. This position is KCP&L's adjustment 4 CS-37 sponsored by Ronald Klote./ KCP&L filed this position prior to the Co:mrtlission's 5 decision in 18-107. We now have the 18-107 Order which selected the SAFESTOR 6 decommissioning methodology which is lengthier and more expensive than the 7 decommissioning 1, | ||
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Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS I | Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS I | ||
Exoected Prooosed Portfolio Performance I | Exoected Prooosed Portfolio Performance I 2018 | ||
2018 | |||
-- !(gP_~~ - -- . | -- !(gP_~~ - -- . | ||
Exoected Returns -.JPMAivt' Large Company Stocks 9.59% 6.41%1 Small Company Stocks 10.65% 7.35%1 International Stocks 8.46% 7.61% | Exoected Returns -.JPMAivt' Large Company Stocks 9.59% 6.41%1 Small Company Stocks 10.65% 7.35%1 International Stocks 8.46% 7.61% | ||
| Line 401: | Line 389: | ||
0.62% | 0.62% | ||
4.2}'.Yo 2.00% | 4.2}'.Yo 2.00% | ||
I Sources: I KCC-258 I J.P. Morgan Asset Management | I Sources: I KCC-258 I J.P. Morgan Asset Management Long-Term Capital Market Assumptions 1 | ||
Long-Term Capital Market Assumptions 1 | |||
2 These are marked differences in returns for almost every asset class. Under Staffs 3 assumptions, in a portfolio of these assets, this differe11ce results in a 100 basis point 4 lower annual return from many of the years. | 2 These are marked differences in returns for almost every asset class. Under Staffs 3 assumptions, in a portfolio of these assets, this differe11ce results in a 100 basis point 4 lower annual return from many of the years. | ||
5 Q. Is JPMAM' s publication a reasonable source for these types. of forecasts? | 5 Q. Is JPMAM' s publication a reasonable source for these types. of forecasts? | ||
6 A. Yes, J.P. Morgan's forecasts in this publication are consistent with forecasted returns by 7 other money management firms and_ reflect the expected returns of institutional portfolio 8 managers. | 6 A. Yes, J.P. Morgan's forecasts in this publication are consistent with forecasted returns by 7 other money management firms and_ reflect the expected returns of institutional portfolio 8 managers. | ||
9 Q. Historically, what has KCP&L's NDT earned? | 9 Q. Historically, what has KCP&L's NDT earned? | ||
| Line 447: | Line 432: | ||
6 Setting the rate of returri requires decisions on °the cost of debt, the cost of equity, and the 7 weight of each in the 1:1tility's capital structure. Staff is preparing its revenue requirement 8 incorporating an update to June 30;2018, from the September 30, 2017, balances used in 9 the Application. The ROR that I recommend is based on the updated account balance_s and 10 costs for the capital items. The update to Section 7 results in a minor change in the ROR 11 from KCP&L's position due a small change in the capital ratios of debt and equity. I agree . | 6 Setting the rate of returri requires decisions on °the cost of debt, the cost of equity, and the 7 weight of each in the 1:1tility's capital structure. Staff is preparing its revenue requirement 8 incorporating an update to June 30;2018, from the September 30, 2017, balances used in 9 the Application. The ROR that I recommend is based on the updated account balance_s and 10 costs for the capital items. The update to Section 7 results in a minor change in the ROR 11 from KCP&L's position due a small change in the capital ratios of debt and equity. I agree . | ||
12 with the capital 'structure and. cost of debt contained in KCP&L's update. | 12 with the capital 'structure and. cost of debt contained in KCP&L's update. | ||
13 Capital Structure 14 Q. Do you have any adjustments to KCP&L's capital structure? | 13 Capital Structure 14 Q. Do you have any adjustments to KCP&L's capital structure? | ||
15 A. No. I.am using the capitalization ratios of June 30, 2018. | 15 A. No. I.am using the capitalization ratios of June 30, 2018. | ||
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AIJjant Energy Corp LNT ~ | AIJjant Energy Corp LNT ~ | ||
48.6% 52.8% . 49.0% | 48.6% 52.8% . 49.0% | ||
50,0% 50.0% | 50,0% 50.0% | ||
50.0% | 50.0% | ||
Ameren Corp AEE 49.3% 47.7% 49.5% 49.5% 49.0% 49.0% | Ameren Corp AEE 49.3% 47.7% 49.5% 49.5% 49.0% 49.0% | ||
American Electric Power Co. AEP 49.8% 50.0% 51.5% 52.5% 54.5% 50.5% | American Electric Power Co. AEP 49.8% 50.0% 51.5% 52.5% 54.5% 50.5% | ||
| Line 471: | Line 452: | ||
IDACORP Inc IDA 45.6% "44,8% -- - . | IDACORP Inc IDA 45.6% "44,8% -- - . | ||
43.7% 44.0% | 43.7% 44.0% | ||
42.0% | 42.0% | ||
. -- 44.0% | . -- 44.0% | ||
NorthWestern Corporation NWE - | NorthWestern Corporation NWE - | ||
53.1% | 53.1% | ||
52.0% 50.2% 49.5% 48.5% 46:0:o. | 52.0% 50.2% 49.5% 48.5% 46:0:o. | ||
OGE Energy Corp OGE 44.3% 41.1% 41.7% 43.0% 44.0% 45.5% | OGE Energy Corp OGE 44.3% 41.1% 41.7% 43.0% 44.0% 45.5% | ||
Pinnacle West Capital Corp PNW 43.0%* 45.6% 48.9% 48.0% 48.5% 45.5% | Pinnacle West Capital Corp PNW 43.0%* 45.6% 48.9% 48.0% 48.5% 45.5% | ||
Portland General Electric Co. POR 47.8% | Portland General Electric Co. POR 47.8% | ||
48.4% 50.1% 47.0% 50.5% 48.5% | 48.4% 50.1% 47.0% 50.5% 48.5% | ||
Xcel Energy Inc XEL 54.1%: 56.3% 55.9% 58.0% 57.0% 58.0% | Xcel Energy Inc XEL 54.1%: 56.3% 55.9% 58.0% 57.0% 58.0% | ||
| Line 490: | Line 467: | ||
Max 54.1%: 56.3% | Max 54.1%: 56.3% | ||
* 55.9% 58.0% 57.0% 58.0% | * 55.9% 58.0% 57.0% 58.0% | ||
Source: Value-Line Investment Survey (April 27, 2018; May 18, 2018; and June 15, 2018) I | Source: Value-Line Investment Survey (April 27, 2018; May 18, 2018; and June 15, 2018) I | ||
-6 7 Q. Is KCP&L's updated capitalization consistent with the capital structure limitations 8 discussed in the 18-095 S&A? | -6 7 Q. Is KCP&L's updated capitalization consistent with the capital structure limitations 8 discussed in the 18-095 S&A? | ||
| Line 511: | Line 487: | ||
8 A. The added risks to shareholders include: | 8 A. The added risks to shareholders include: | ||
9 | 9 | ||
* a five-year rate moratorium during which KCP&L carinot file a rate case in 10 Kansas* 7 | * a five-year rate moratorium during which KCP&L carinot file a rate case in 10 Kansas* 7 11 | ||
11 | |||
* upfront bill credits to KCP&L Kansas customers totaling $7,514,220; 8 12 | * upfront bill credits to KCP&L Kansas customers totaling $7,514,220; 8 12 | ||
* minimum annual credits to consumers of$2,817,832 by March 3pt of 2019, 2020, 13 2021, and 2022; 9 14 * $7,468,874 million of merger savings built into the revenue requirement in this 15 rate case* 1° and | * minimum annual credits to consumers of$2,817,832 by March 3pt of 2019, 2020, 13 2021, and 2022; 9 14 * $7,468,874 million of merger savings built into the revenue requirement in this 15 rate case* 1° and 16 | ||
16 | |||
* an Earnings Review and Sharing Plan for excess earnings above the 9.30% | * an Earnings Review and Sharing Plan for excess earnings above the 9.30% | ||
17 allowed return for years 2020, 2021, 2022, and 2023. 11 18 Staff believes the ~ 8-095 S&A presents additional risks to shareholders because it demands 19 annual credits to consumers that has the effect oflowering KCP&L's earned return; reduces 20 the value of earnings if KCP~L earns above its allowed return; sets a period of five years 21 during which KCP&L cannot file a rate case if its earnings are less than its allowed return; 22 and sets a period of five years during which KCP&L cannot file a rate case if its capital 23 costs increase. With the 18-095 S&A in place that sets a period of five years during which 6 | 17 allowed return for years 2020, 2021, 2022, and 2023. 11 18 Staff believes the ~ 8-095 S&A presents additional risks to shareholders because it demands 19 annual credits to consumers that has the effect oflowering KCP&L's earned return; reduces 20 the value of earnings if KCP~L earns above its allowed return; sets a period of five years 21 during which KCP&L cannot file a rate case if its earnings are less than its allowed return; 22 and sets a period of five years during which KCP&L cannot file a rate case if its capital 23 costs increase. With the 18-095 S&A in place that sets a period of five years during which 6 | ||
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7 Q. Do you believe the Commission. can deviate from the 9.30% ROE even though it adopted th~ 18-095 S&A? \ | 7 Q. Do you believe the Commission. can deviate from the 9.30% ROE even though it adopted th~ 18-095 S&A? \ | ||
9 A. Yes, certainly that is well within the Commission's rights if it believes the evidence cannot 10 support the allowed return sought in the 18-095 S&A. If the Commission adopts an ROE 11 lower than 9.30%, KCP&L has the option of shortening the rate moratorium from five 12 | 9 A. Yes, certainly that is well within the Commission's rights if it believes the evidence cannot 10 support the allowed return sought in the 18-095 S&A. If the Commission adopts an ROE 11 lower than 9.30%, KCP&L has the option of shortening the rate moratorium from five 12 | ||
* years to three years. Staff believes there are benefits for consumers to the full five-year 13 | * years to three years. Staff believes there are benefits for consumers to the full five-year 13 rate moratorium that may not be present in a three-year moratorium, such as an incentive 14 to capture merger relat~d synergies and a period of relative rate stability. Those are two 15 examples that are not easily quantified but Staff believes them to be beneficial to-16 consumers. | ||
17 Q. How does a 9.30% ROE compare to recent decisions from around the country? | 17 Q. How does a 9.30% ROE compare to recent decisions from around the country? | ||
18 A. A 9.30% return on equity is at the low-end of recent observations for electric utility rate 19 cases. For the first six;.months of 2018, the average ROE granted was 9.74% with thirteen 13 Non-Unanimous Settlement Agreement; 18-KCPE-095-MER filed March 17, 2018; at paragraph 32, iv, I; p. 15. | 18 A. A 9.30% return on equity is at the low-end of recent observations for electric utility rate 19 cases. For the first six;.months of 2018, the average ROE granted was 9.74% with thirteen 13 Non-Unanimous Settlement Agreement; 18-KCPE-095-MER filed March 17, 2018; at paragraph 32, iv, I; p. 15. | ||
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6/29/2018 Hawaii Electric Light Co., Inc. HI 9.50% | 6/29/2018 Hawaii Electric Light Co., Inc. HI 9.50% | ||
9.74% | 9.74% | ||
Source: | Source: | ||
-- "---- - -- - - -. - "" ~ | -- "---- - -- - - -. - "" ~ | ||
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Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 over-lapping tim~ periods that cover a total of nineteen months from January 1, 2017, 2 through July 3, 2018. | Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 over-lapping tim~ periods that cover a total of nineteen months from January 1, 2017, 2 through July 3, 2018. | ||
Comparison of Staff ReC(_)f!!l_ll~!1~:la!~~11s ~c_ross 18-KCPE-095-MER Related Dockets Interest Rates Observed for Risk Premium Calculations | Comparison of Staff ReC(_)f!!l_ll~!1~:la!~~11s ~c_ross 18-KCPE-095-MER Related Dockets Interest Rates Observed for Risk Premium Calculations | ||
_30_¥<<;_~- _ Util_ityB_o~~ . ___ Mo_o_d)"s _ Bond Treasury Bond A/A Baa/BBB Corporate Baa YfM* ' | _30_¥<<;_~- _ Util_ityB_o~~ . ___ Mo_o_d)"s _ Bond Treasury Bond A/A Baa/BBB Corporate Baa YfM* ' | ||
| Line 636: | Line 605: | ||
*lf. M~rga_!l ~~Se! ~a~!l_e~_n! (~_1..8 edip~n)_ | *lf. M~rga_!l ~~Se! ~a~!l_e~_n! (~_1..8 edip~n)_ | ||
9 10 Q. For a point of comparison, please summarize return on equity decisions by this 11 Commission and Commissions across the country? | 9 10 Q. For a point of comparison, please summarize return on equity decisions by this 11 Commission and Commissions across the country? | ||
12 A. The first table contains allowed return on equity decisions made by this Commission in 13 litigated rate cases. As a point of reference to the prevailing capital markets at that time, I 18 | 12 A. The first table contains allowed return on equity decisions made by this Commission in 13 litigated rate cases. As a point of reference to the prevailing capital markets at that time, I 18 | ||
| Line 656: | Line 624: | ||
4/15/19961-- -- *12.00%1 w..sw.1-- --- 7.77%1 1 | 4/15/19961-- -- *12.00%1 w..sw.1-- --- 7.77%1 1 | ||
-* i _____ .l_ ____ ____J_ ____ -~- ------ ___ )__________ :_ | -* i _____ .l_ ____ ____J_ ____ -~- ------ ___ )__________ :_ | ||
*Sources: SNURRA; Federal Reserve Banlc of St. Louis, FRED | *Sources: SNURRA; Federal Reserve Banlc of St. Louis, FRED | ||
---rI --- -- --T: --r! | ---rI --- -- --T: --r! | ||
| Line 675: | Line 642: | ||
--- *::~-...~... - ............j;...* | --- *::~-...~... - ............j;...* | ||
* i * -- _--- | * i * -- _--- | ||
... ... -... A-_A:-.. ---- --- -- -- --- | ... ... -... A-_A:-.. ---- --- -- -- --- | ||
10.00% --- ------- ---- --.- -- - - - - - -- ...........- -...- -...- | 10.00% --- ------- ---- --.- -- - - - - - -- ...........- -...- -...- | ||
| Line 735: | Line 701: | ||
* 4.32% | * 4.32% | ||
Equity Risk Premium Over "Baa/BBB" Utility Bond Yield 4.98% | Equity Risk Premium Over "Baa/BBB" Utility Bond Yield 4.98% | ||
I I KCC Staffs Recommended ROE 9.30% | I I KCC Staffs Recommended ROE 9.30% | ||
Average Yield on "BBB/Baa" Rated Utility Bonds 4.44% | Average Yield on "BBB/Baa" Rated Utility Bonds 4.44% | ||
| Line 798: | Line 763: | ||
American Electric Power Company Inc AEP Baal A- Yes *X X 94.1% | American Electric Power Company Inc AEP Baal A- Yes *X X 94.1% | ||
QllQl:IJQIW) iAii. AGR Baal BBB+ | QllQl:IJQIW) iAii. AGR Baal BBB+ | ||
Yes X | Yes X | ||
X | X | ||
| Line 805: | Line 769: | ||
81.0% 85.7% | 81.0% 85.7% | ||
~ AVA *Hyjro-One Merger* _ | ~ AVA *Hyjro-One Merger* _ | ||
lllaol, Uills Go,p BKH *Selling oil & gas assets* | lllaol, Uills Go,p BKH *Selling oil & gas assets* | ||
-- 31.7% 45.4% | -- 31.7% 45.4% | ||
CeateFl!eiRt SeeFffii1 Im; CNP Baal A- Yes X X X CHi liRBFre Gerp CMS Baal BBB+ Yes X X X 67.5% 60.3% | CeateFl!eiRt SeeFffii1 Im; CNP Baal A- Yes X X X CHi liRBFre Gerp CMS Baal BBB+ Yes X X X 67.5% 60.3% | ||
Consolidated Edison Inc . ED A3 A- Y_es X X X 76.6% 73.3% | Consolidated Edison Inc . ED A3 A- Y_es X X X 76.6% 73.3% | ||
DamiRiaA S1ier~ D *AcquiriJ:tg SCANA* | DamiRiaA S1ier~ D *AcquiriJ:tg SCANA* | ||
l'J:rJ; ll**'l!l' G*'"l'*"l' DTE Baal BBB+ Yes X X X 40.5% 62.7% | l'J:rJ; ll**'l!l' G*'"l'*"l' DTE Baal BBB+ Yes X X X 40.5% 62.7% | ||
| Line 857: | Line 819: | ||
~_oody's_ S&P Aaa AM | ~_oody's_ S&P Aaa AM | ||
. Aal AA+ | . Aal AA+ | ||
"O o:I Aa2 Aa3 AA AA- | |||
"O o:I | |||
Aa2 | |||
Aa3 AA AA- | |||
".= . Al A+ | ".= . Al A+ | ||
s."' A2 A3 A | s."' A2 A3 A | ||
| Line 868: | Line 825: | ||
- i: Baal Baa2 Baa3 BBB+ | - i: Baal Baa2 Baa3 BBB+ | ||
BBB BBB-B_al ~B+ | BBB BBB-B_al ~B+ | ||
. Ba2 BB | . Ba2 BB "O | ||
o:I Ba3 BB- | |||
"...=. Bl B2 | "...=. Bl B2 | ||
--~ | --~ | ||
| Line 881: | Line 837: | ||
CCC- | CCC- | ||
- - - -cc Ca | - - - -cc Ca | ||
...l C+ | ...l C+ | ||
C 23 C D 27 | C 23 C D 27 | ||
| Line 922: | Line 876: | ||
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS Bond Ratings of Evergy, Inc. | Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS Bond Ratings of Evergy, Inc. | ||
& Kansas Jurisdictional Subsidiaries Pre-Merger Rating/ Post-Merger Bond Rating Standard | & Kansas Jurisdictional Subsidiaries Pre-Merger Rating/ Post-Merger Bond Rating Standard | ||
&Poors' Moody's Evergy, Inc./Great Plains Energy BBB+/ A- Baa2/Baa2 Kansas City Power & Light BBB+/ A- Baal/ Baal W~s~r E_f!~~gy_ _ BBB+/ A- Baal/ Baal | &Poors' Moody's Evergy, Inc./Great Plains Energy BBB+/ A- Baa2/Baa2 Kansas City Power & Light BBB+/ A- Baal/ Baal W~s~r E_f!~~gy_ _ BBB+/ A- Baal/ Baal Kansas Gas & Electric BBB+/ A- Baal/ Baal Source: S&P Global Market Intelligence 1 | ||
Kansas Gas & Electric BBB+/ A- Baal/ Baal Source: S&P Global Market Intelligence 1 | |||
2 Return on Equity Analysis 3 Q. How did you perform the cost of equity analysis? | 2 Return on Equity Analysis 3 Q. How did you perform the cost of equity analysis? | ||
4 A. I am using discounted cash flow models and capital asset pricing models; identical to the 5 methods used in recent rate cases: the 18-095 Docket and 18-328 Docket to establish the 6 9.30% threshold for the ERSP. | 4 A. I am using discounted cash flow models and capital asset pricing models; identical to the 5 methods used in recent rate cases: the 18-095 Docket and 18-328 Docket to establish the 6 9.30% threshold for the ERSP. | ||
| Line 943: | Line 895: | ||
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-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 Or 5 Stock Price= Annual Dividend/ (Req'd Rate of Return -Dividend Growth Rate) 6 This is the form of the equation commonly found in texts regarding finance, investments, 7 and asset valuation. Such texts are inclusive of both theory and practical application. | Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-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 Or 5 Stock Price= Annual Dividend/ (Req'd Rate of Return -Dividend Growth Rate) 6 This is the form of the equation commonly found in texts regarding finance, investments, 7 and asset valuation. Such texts are inclusive of both theory and practical application. | ||
8 Regulatory agencies responsible for setting rates and revenue requirements want to know 9 the investors' required rate of return or Ke in the equation. So, we solve the equation for 10 that variable. The equation below shows the algebraic isolation of the investors' required 11 rate of return. By isolating investors' required rate of return in the equation, we can | 8 Regulatory agencies responsible for setting rates and revenue requirements want to know 9 the investors' required rate of return or Ke in the equation. So, we solve the equation for 10 that variable. The equation below shows the algebraic isolation of the investors' required 11 rate of return. By isolating investors' required rate of return in the equation, we can | ||
* 12 estimate it by knowing the stock's dividend yield and the annual dividend growth rate 13 expected by investors. That form of the equation is: | * 12 estimate it by knowing the stock's dividend yield and the annual dividend growth rate 13 expected by investors. That form of the equation is: | ||
| Line 980: | Line 931: | ||
Consolidated )3dison Inc ED | Consolidated )3dison Inc ED | ||
. - *- $ 2.96 $. IJ-~2- $- . 89.70 $ 80.41 $ 80.75 3.30% 4.16% | . - *- $ 2.96 $. IJ-~2- $- . 89.70 $ 80.41 $ 80.75 3.30% 4.16% | ||
Duke Energy Corp New DUK | Duke Energy Corp New DUK | ||
$ *:i:so $. ?_L96 $ 91.80. _$ 81.88__ $81.78 _ 4.14% | $ *:i:so $. ?_L96 $ 91.80. _$ 81.88__ $81.78 _ 4.14% | ||
5.28% | 5.28% | ||
Edison International EIX $ 2.57 ~- ~?,6°? $ 83.38 ; $ ---*-- | Edison International EIX $ 2.57 ~- ~?,6°? $ 83.38 ; $ ---*-- | ||
70.50 $ 69.71 3.08% 4.46% | 70.50 $ 69.71 3.08% 4.46% | ||
El Paso Electric Co EE | El Paso Electric Co EE | ||
$ 1.52 | $ 1.52 | ||
.. --- $ 48.05 $ 61.15 $ 54.60 $54.44 2.49% 3.16% | .. --- $ 48.05 $ 61.15 $ 54.60 $54.44 2.49% 3.16% | ||
IDACORP Inc IDA $ 2.56 $ 79.59 $ 100.04 $ 89.81 $ 89.08 2.56% 3.22% | IDACORP Inc IDA $ 2.56 $ 79.59 $ 100.04 $ 89.81 $ 89.08 2.56% 3.22% | ||
NorthWestern Corp_1?ration NWE $ 2.30 $ 50.01 $ 64.47; ~ 57.24 $_56.88 3.57% 4.60% | NorthWestern Corp_1?ration NWE $ 2.30 $ 50.01 $ 64.47; ~ 57.24 $_56.88 3.57% 4.60% | ||
OGE Energy_f~--- OGE | OGE Energy_f~--- OGE | ||
$ 1.54 $ 29.59 $ 37.32 $ 33.46 $34.06 4.13% 5.20% | $ 1.54 $ 29.59 $ 37.32 $ 33.46 $34.06 4.13% 5.20% | ||
Pinnacle West Capital Corp_ PNW | Pinnacle West Capital Corp_ PNW | ||
$ 3.02 $ 73.41 $ 92.48 $ 82.95 $ 83.23 3.27% 4)J~ | $ 3.02 $ 73.41 $ 92.48 $ 82.95 $ 83.23 3.27% 4)J~ | ||
Portland General Electric Co. POR | Portland General Electric Co. POR | ||
-------* ! 1.50 $_}~Q2 $ 50.11 $.. 44.57 ~~~:27 .. 2.99% | -------* ! 1.50 $_}~Q2 $ 50.11 $.. 44.57 ~~~:27 .. 2.99% | ||
| Line 1,016: | Line 955: | ||
- I) Maximum 12 month price observed from July 2, 2017 thr~gh July_3, 2018 | - I) Maximum 12 month price observed from July 2, 2017 thr~gh July_3, 2018 | ||
~~~- -~_::==-~-- | ~~~- -~_::==-~-- | ||
~~= | ~~= | ||
_ ~ Mid-point is the average of minimum price and maximum price _ _ .. ___ ... _ _ _ _ ___ _ | _ ~ Mid-point is the average of minimum price and maximum price _ _ .. ___ ... _ _ _ _ ___ _ | ||
- ~ Mean price for the time period ofJuly 2, 2017 through Jul_y 3, 2018 ~eek!Y. <!~~ervations)_ ____ _ _ _ _ | - ~ Mean price for the time period ofJuly 2, 2017 through Jul_y 3, 2018 ~eek!Y. <!~~ervations)_ ____ _ _ _ _ | ||
| Line 1,097: | Line 1,034: | ||
______ | ______ | ||
* _____ Discounted Cash Flow (DCF) Analysis -----------* __ | * _____ Discounted Cash Flow (DCF) Analysis -----------* __ | ||
18-KCPE-480-RTS | 18-KCPE-480-RTS I 2 3 4 5 Dividend Yields Growth DCF Estimated Min Max Rate Required Return | ||
I 2 3 4 5 Dividend Yields Growth DCF Estimated Min Max Rate Required Return | |||
'Allele Inc ALE 2.88% 3.51% 4.91% 7.79% 8.42% | 'Allele Inc ALE 2.88% 3.51% 4.91% 7.79% 8.42% | ||
Alliant Energy Corp LNT 3.12% 3.85% 5.18% 8.30% 9.04% | Alliant Energy Corp LNT 3.12% 3.85% 5.18% 8.30% 9.04% | ||
| Line 1,112: | Line 1,047: | ||
NorthWestern Corp. NWE 3.57% 4.60% 3.92% 7.49% 8.52% | NorthWestern Corp. NWE 3.57% 4.60% 3.92% 7.49% 8.52% | ||
OGE Energy Corp _ _}2GE 4.13% 5.20% 4.95% 9.08% 10.15% | OGE Energy Corp _ _}2GE 4.13% 5.20% 4.95% 9.08% 10.15% | ||
Pinnacle West Capital Corp PNW 3.27% 4.11% 4.50% 7.77% 8.62% | Pinnacle West Capital Corp PNW 3.27% 4.11% 4.50% 7.77% 8.62% | ||
Portland General Electric Co. POR 2.99% 3.84% 4.11% 7.10% 7.95% | Portland General Electric Co. POR 2.99% 3.84% 4.11% 7.10% 7.95% | ||
Xcel Energy Inc XEL 3.06% 3.85% 4.97% 8.03% 8.82% | Xcel Energy Inc XEL 3.06% 3.85% 4.97% 8.03% 8.82% | ||
Average of each colwnn 7.84% 8.71% | Average of each colwnn 7.84% 8.71% | ||
| Line 1,145: | Line 1,078: | ||
Edison International EIX 2.50% 6.00% 2.50% 9.00% 4.50% 8.00% 3.19% 4.10%* 4.95% 4.30% 4.62% | Edison International EIX 2.50% 6.00% 2.50% 9.00% 4.50% 8.00% 3.19% 4.10%* 4.95% 4.30% 4.62% | ||
1 El Paso Electric Co. EE _ 6.50% _ 0.00% -- 0.00% !8.00% 4.50% 7.00% 5.20% 5.10% 5.45% 4.30% 4.88% | 1 El Paso Electric Co. EE _ 6.50% _ 0.00% -- 0.00% !8.00% 4.50% 7.00% 5.20% 5.10% 5.45% 4.30% 4.88% | ||
IDACORP Inc. IDA 7 ..50,'!'o 5,_50~ * ' 4.5.QY., 10.50% 3.50% 6.50% 3.55% 3.91%: 4.37% 4.30% 4.33% | IDACORP Inc. IDA 7 ..50,'!'o 5,_50~ * ' 4.5.QY., 10.50% 3.50% 6.50% 3.55% 3.91%: 4.37% 4.30% 4.33% | ||
NorthWestern Corp. NWE *- 8.00% _ 5.50% 7.00% _ 7.00% 3.50% 4.50% 3.16% ___3.01%, __ 3.54% 4.30% 3.92% | NorthWestern Corp. NWE *- 8.00% _ 5.50% 7.00% _ 7.00% 3.50% 4.50% 3.16% ___3.01%, __ 3.54% 4.30% 3.92% | ||
OGE Energy Corp. 4.50% 4.30% .. 410%: | OGE Energy Corp. 4.50% 4.30% .. 410%: | ||
Pinnacle West Capital Corp. PNW OGE 4.00% 2.50% | Pinnacle West Capital Corp. PNW OGE 4.00% 2.50% | ||
-*--- 5.50% 1.00%-- 8.50% | -*--- 5.50% 1.00%-- 8.50% | ||
5.00% 2.50% | 5.00% 2.50% | ||
| Line 1,157: | Line 1,088: | ||
8.00% | 8.00% | ||
5.50% | 5.50% | ||
3.78% 4'.54%1 5.60% | 3.78% 4'.54%1 5.60% | ||
4.70% | 4.70% | ||
4.30% | 4.30% | ||
| Line 1,203: | Line 1,132: | ||
1 NorthWestern Corp. 8.58% | 1 NorthWestern Corp. 8.58% | ||
,OGE Energy Corp. 9.47% | ,OGE Energy Corp. 9.47% | ||
!Pinnacle West Capital Corp. 8.28%' | !Pinnacle West Capital Corp. 8.28%' | ||
,Portland General Electric Co. 7.93% | ,Portland General Electric Co. 7.93% | ||
| Line 1,237: | Line 1,165: | ||
7 Reviewing the high and low beta coefficients observed in the proxy group provides a 8 picture of the range that the new company could exhibit in the future. | 7 Reviewing the high and low beta coefficients observed in the proxy group provides a 8 picture of the range that the new company could exhibit in the future. | ||
B~tl! Co~!~c~nt~,_s~l!rr~ P.!_OE G~~P Updated on July 24, 2018 18-KCPE-480-RTS Allete Inc ALE 0.75. | B~tl! Co~!~c~nt~,_s~l!rr~ P.!_OE G~~P Updated on July 24, 2018 18-KCPE-480-RTS Allete Inc ALE 0.75. | ||
Allfl!~t E.~<::!gy CC!_rJJ LNT 0.70 Ameren Corp_ AEE 0.65 American | Allfl!~t E.~<::!gy CC!_rJJ LNT 0.70 Ameren Corp_ AEE 0.65 American Electric- Power | ||
Electric- Power | |||
... . Co Inc AEP 0.65 | ... . Co Inc AEP 0.65 | ||
:Consolidated Edison Inc ED 0.50 | :Consolidated Edison Inc ED 0.50 | ||
| Line 1,278: | Line 1,204: | ||
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS | Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS | ||
---~--C_apital Asset Pricing Model -- Historic Risk Premium Based on Historic ----- Risk Premiums from 1926 to 2015 | ---~--C_apital Asset Pricing Model -- Historic Risk Premium Based on Historic ----- Risk Premiums from 1926 to 2015 | ||
--- ---------~--------- | --- ---------~--------- | ||
| Line 1,290: | Line 1,215: | ||
9.38% | 9.38% | ||
I | I | ||
: 1) 1Historic returns on common stocks 1926-2017 (SBBI; Exhibit 2-3) | : 1) 1Historic returns on common stocks 1926-2017 (SBBI; Exhibit 2-3) | ||
: 2) ;Historic returns on intermediate-term government bonds 1926-2017 | : 2) ;Historic returns on intermediate-term government bonds 1926-2017 | ||
: 3) \~eslllrjng_risk IJr_el!lil_ll!lJl-2) _ | : 3) \~eslllrjng_risk IJr_el!lil_ll!lJl-2) _ | ||
4):Beta coefficient ofthe proxy grm.l}l (Reported by Value-Line) 5)IRow I *-* | 4):Beta coefficient ofthe proxy grm.l}l (Reported by Value-Line) 5)IRow I *-* | ||
3 xRow 4 = As~et S}lecific | 3 xRow 4 = As~et S}lecific Risk:P;e~~ | ||
Risk:P;e~~ | |||
*. - -*-*-*. --*-*-* ~--- - | *. - -*-*-*. --*-*-* ~--- - | ||
: 6) 1Historic year-end yield on intermediate-term government bonds 1926-2017 7);F~rei:~t~d~o~t~f~q~ty-capi~!;_r_~~5+-~~~6 * * -- * - | : 6) 1Historic year-end yield on intermediate-term government bonds 1926-2017 7);F~rei:~t~d~o~t~f~q~ty-capi~!;_r_~~5+-~~~6 * * -- * - | ||
Sources:---- ---- ---- ---- | Sources:---- ---- ---- ---- | ||
| Line 1,323: | Line 1,244: | ||
*** Table 3.2 SAFESTOR Alternative (thousands, 2017 $'s) Cost Categories *** Time 2017 Dollars Equip & from Total KCP&L Year Labor Materials Energy Burial Other Total 2017 Inflated Costs KS Allocated 2087 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 70 $ 33,408,789 $ 6,878,899 2088 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 71 $ 34,393,851 * $ 7,081,724 2089 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 72 $ 35,228,375 $ 7,253,554 2090 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 73 $ 36,175,823 $ 7,448,634 2091 $ 3,437 $ 322 $ 243 $ 7 $ -1,370 $ 5,379 74 $ 37,149,327 $ 7,649,079 2092 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 75 $ 38,246,858 $ 7,875,062 2093 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 76 $ 39,177,485 $ 8,066,679 2094 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 77 $ 40,233,688 $ 8,284,152 2095 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 78 $ 41,319,046 $ 8,507,628 2096 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 79 $ 42,542,342 $ 8,759,506 2097 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 80 $ 43,580,588 $ 8,973,281 2098 $* 8,030 $ 526 $ 530 $ IO $ 1,416 $ 10,512 81 $ 91,483,641 $ 18,836,562 2099 $ 39,843 $ 3,003 $ 2,428 $" 35 $ 1,725 $ 47,034 82 $ 430,839,660 $ 88,710,266 2100 $ 51,668 $ 21,348 $ 2,352 $ 19,715 $ 11,194 $ 106,277 83 $ 2,662,274,613 $ 548,164,690 2101 $ 52,224 $ 26,356 $ 2,272 $ 29,879 $ 16,007 $ 126,738 84 $ 3,922,244,251 $ 807,593,549 2102 $ 43,514 $ 7,481 $ 1,821 $ 10,054 $ 5,614 $ 68,484 85 $ 1,662,739,234 $ 342,359,474 2103 $ 43,514 $ 7,481 $ 1,821 $ 1)0,054 $ 5,614 $ 68,484 86 $ 1,741,171,137 $ 358,508,672 2104 $ 36,028- $ 4,171 $ 1,047 $ 4,233 $ 3,422 $ 48,901 87 $ 978,573,603 $ 201,489,168 2105 $ 19,989 $ 11,805 $ 289 $ 6. $ 1,828 $ 33,917 88 $ 300,897,026 $ 61,954,963 2106 $ 11,872 $ 9,571 $ 164 $ $ 1,237 $ 22,844 89 $ 196,446,660 $ 40,448,540 Total $ 676,450 $ 142,715 $ 29,816 $ 75,796 $ 168,376 $ 1,093,153 Source: Decommissioning Cost Analysis for the Wolf Creek Generating Station; prepared by TLG Services; August 2017; Table 3.2; p68 of 139 Kansas allocator for Wolf Creek; KCC DR #164 43.8% | *** Table 3.2 SAFESTOR Alternative (thousands, 2017 $'s) Cost Categories *** Time 2017 Dollars Equip & from Total KCP&L Year Labor Materials Energy Burial Other Total 2017 Inflated Costs KS Allocated 2087 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 70 $ 33,408,789 $ 6,878,899 2088 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 71 $ 34,393,851 * $ 7,081,724 2089 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 72 $ 35,228,375 $ 7,253,554 2090 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 73 $ 36,175,823 $ 7,448,634 2091 $ 3,437 $ 322 $ 243 $ 7 $ -1,370 $ 5,379 74 $ 37,149,327 $ 7,649,079 2092 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 75 $ 38,246,858 $ 7,875,062 2093 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 76 $ 39,177,485 $ 8,066,679 2094 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 77 $ 40,233,688 $ 8,284,152 2095 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 78 $ 41,319,046 $ 8,507,628 2096 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 79 $ 42,542,342 $ 8,759,506 2097 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 80 $ 43,580,588 $ 8,973,281 2098 $* 8,030 $ 526 $ 530 $ IO $ 1,416 $ 10,512 81 $ 91,483,641 $ 18,836,562 2099 $ 39,843 $ 3,003 $ 2,428 $" 35 $ 1,725 $ 47,034 82 $ 430,839,660 $ 88,710,266 2100 $ 51,668 $ 21,348 $ 2,352 $ 19,715 $ 11,194 $ 106,277 83 $ 2,662,274,613 $ 548,164,690 2101 $ 52,224 $ 26,356 $ 2,272 $ 29,879 $ 16,007 $ 126,738 84 $ 3,922,244,251 $ 807,593,549 2102 $ 43,514 $ 7,481 $ 1,821 $ 10,054 $ 5,614 $ 68,484 85 $ 1,662,739,234 $ 342,359,474 2103 $ 43,514 $ 7,481 $ 1,821 $ 1)0,054 $ 5,614 $ 68,484 86 $ 1,741,171,137 $ 358,508,672 2104 $ 36,028- $ 4,171 $ 1,047 $ 4,233 $ 3,422 $ 48,901 87 $ 978,573,603 $ 201,489,168 2105 $ 19,989 $ 11,805 $ 289 $ 6. $ 1,828 $ 33,917 88 $ 300,897,026 $ 61,954,963 2106 $ 11,872 $ 9,571 $ 164 $ $ 1,237 $ 22,844 89 $ 196,446,660 $ 40,448,540 Total $ 676,450 $ 142,715 $ 29,816 $ 75,796 $ 168,376 $ 1,093,153 Source: Decommissioning Cost Analysis for the Wolf Creek Generating Station; prepared by TLG Services; August 2017; Table 3.2; p68 of 139 Kansas allocator for Wolf Creek; KCC DR #164 43.8% | ||
KCP&L Ownership 47.0% | KCP&L Ownership 47.0% | ||
Schedule AHG-1 18-KCPE-480-RTS Kansas City Power & Light-Ks SAFESTOR Decommissioning | Schedule AHG-1 18-KCPE-480-RTS Kansas City Power & Light-Ks SAFESTOR Decommissioning | ||
| Line 1,352: | Line 1,272: | ||
25 2042 $ 2,036,766 $ $ 16,392,934 $ 372,156,864 4.62% | 25 2042 $ 2,036,766 $ $ 16,392,934 $ 372,156,864 4.62% | ||
26 2043 $ 2,036,766 $ $ 17,244,577 $ 391,438,208 4.62% | 26 2043 $ 2,036,766 $ $ 17,244,577 $ 391,438,208 4.62% | ||
27 28 29 2044 $ | 27 28 29 2044 $ | ||
2045 $. | 2045 $. | ||
2046 $ | 2046 $ | ||
2,036,766 $ | 2,036,766 $ | ||
(27,638,208) | (27,638,208) | ||
(39,631,383) | (39,631,383) 18,135,576 $ | ||
18,135,576 $ | |||
19,020,688 $ | 19,020,688 $ | ||
18,622,469 $ | 18,622,469 $ | ||
| Line 1,535: | Line 1,448: | ||
Earnings Predictability I I' .ll.1!:!lll!'lll!Ull:111111 I | Earnings Predictability I I' .ll.1!:!lll!'lll!Ull:111111 I | ||
85~-. | 85~-. | ||
18-KCPE-480-RTS | 18-KCPE-480-RTS | ||
| Line 1,593: | Line 1,505: | ||
Price Gain | Price Gain | ||
~~s:::::7.f2311if:=:--t---t::::;;;.,./'9----::--r AnR~tJ~al ****~~"-*""-**.Ii "-- | ~~s:::::7.f2311if:=:--t---t::::;;;.,./'9----::--r AnR~tJ~al ****~~"-*""-**.Ii "-- | ||
. .~~\F"i~~~,.,.'4rtl'*'4l*'!lj"F''-"----jf-...:.**:.:-+~:-:-::f:-:--+--f--+--l-40 1..,.-/ 11 ,.,.,,, .. *'' 11111 ''' ,,., --- ** 30 110 High 65 (+15%l 7% r I* .. I I'"' 'T' 25 11 | . .~~\F"i~~~,.,.'4rtl'*'4l*'!lj"F''-"----jf-...:.**:.:-+~:-:-::f:-:--+--f--+--l-40 1..,.-/ 11 ,.,.,,, .. *'' 11111 ''' ,,., --- ** 30 110 High 65 (+15%l 7% r I* .. I I'"' 'T' 25 11 | ||
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| Line 1,640: | Line 1,551: | ||
....... =- | ....... =- | ||
TIMELINESS 4 Lowered 514118 High: 51.2 49.1 36.5 37.9 41.7 45.4 51.6 63.2 65.4 71.3 78.1 73.4 - Target-Price Range Low: 41.7 25.5 24.0 28.2 33.1 37.0 41.8 45.8 52.3 56.8 61.8 63.3 2021 2022 2023 SAFETY 1 Raised3/17117 - | TIMELINESS 4 Lowered 514118 High: 51.2 49.1 36.5 37.9 41.7 45.4 51.6 63.2 65.4 71.3 78.1 73.4 - Target-Price Range Low: 41.7 25.5 24.0 28.2 33.1 37.0 41.8 45.8 52.3 56.8 61.8 63.3 2021 2022 2023 SAFETY 1 Raised3/17117 - | ||
LEGENDS 0.67 x Dividends p sh 128 TECHNICAL 3 Raised 5/25118 . . . . ~~i~r~eb~r/gleffi~ln,~e | LEGENDS 0.67 x Dividends p sh 128 TECHNICAL 3 Raised 5/25118 . . . . ~~i~r~eb~r/gleffi~ln,~e BETA .65 (1.00 = Market) 96 80 o~~~~:/i~a indicates recession ,,;-- ,_,_,.,,111 11 | ||
,:u,n-i3 IIVN;) 64 Price Gain Ann'I Total Return .. ,* .... 11.11 | |||
BETA .65 (1.00 = Market) 96 80 | |||
o~~~~:/i~a indicates recession ,,;-- ,_,_,.,,111 11 | |||
,:u,n-i3 IIVN;) 64 | |||
Price Gain Ann'I Total Return .. ,* .... 11.11 | |||
- ./ | - ./ | ||
1111"' | 1111"' | ||
,,**I' 1111111*11 48 | ,,**I' 1111111*11 48 | ||
,1*11 High 80 (+25%l 9% 40 | ,1*11 High 80 (+25%l 9% 40 | ||
'h * | 'h * | ||
* rff'i"':'1'1"11 *11 1**1h* | * rff'i"':'1'1"11 *11 1**1h* | ||
*1 ..... | *1 ..... | ||
32 | 32 Low 65 (Nil 4% I 1 | ||
1111! | |||
Low 65 (Nil 4% I | |||
Insider Decisions | Insider Decisions | ||
... *.... ***.. ....** ...-... .......... ...* 24 A S O N D J FM A to Buy 0 0 0 0 0 0 0 0 0 Options 0 0 0 0 0 0 0 0 0 | ... *.... ***.. ....** ...-... .......... ...* 24 A S O N D J FM A to Buy 0 0 0 0 0 0 0 0 0 Options 0 0 0 0 0 0 0 0 0 | ||
***-*. --. .........**** 16 to Sell 0 0 0 0 0 0 0 0 0 -12 | ***-*. --. .........**** 16 to Sell 0 0 0 0 0 0 0 0 0 -12 | ||
% TOT. RETURN 5/18 Institutional Decisions MIiii l1m1~111~~11~11 ~~!1~111~~11~1111~~~~11~1~~~~11ll~La THIS VLARITH.' | % TOT. RETURN 5/18 Institutional Decisions MIiii l1m1~111~~11~11 ~~!1~111~~11~1111~~~~11~1~~~~11ll~La THIS VLARITH.' | ||
3Q2017 4Q2017 1Q2018 Percent ,I I STOCK INDEX 15- | 3Q2017 4Q2017 1Q2018 Percent ,I I STOCK INDEX 15-to Buy 388 371 406 shares 10 1 yr. -1.9 14.3 to Sell 351 342 468 traded 5 3yr. 34.5 29.1 Hld'sfOOOf 382879 352776 357126 5yr. 78.8 67.5 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2019 "'VALUE LINE PUB. LLC , 1-23 42.96 36.82 35.51 30.76 31.82 33.41 35.56 28.22 30.01 31.27 30.77 31.48 34.78 33.51 33.31 31.35 32.00 32.85 Revenues per sh 34.50 6.99 5.76 5.89 5.96 6.67 6.80 6.84 6.32 6.29 6.83 6.92 7.02 7.57 7.98 8.47 7.95 8.45 8.90 "Cash Flow" per sh 10.25 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 3.59 4.23 3.62 3.85 4.10 Earnings per sh A 5.00 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 2.39 2.51 2.63 Div'd Decl'd per sh B | ||
to Buy 388 371 406 shares 10 1 yr. -1.9 14.3 to Sell 351 342 468 traded 5 3yr. 34.5 29.1 Hld'sfOOOf 382879 352776 357126 5yr. 78.8 67.5 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2019 "'VALUE LINE PUB. LLC , 1-23 42.96 36.82 35.51 30.76 31.82 33.41 35.56 28.22 30.01 31.27 30.77 31.48 34.78 33.51 33.31 31.35 32.00 32.85 Revenues per sh 34.50 6.99 5.76 5.89 5.96 6.67 6.80 6.84 6.32 6.29 6.83 6.92 7.02 7.57 7.98 8.47 7.95 8.45 8.90 "Cash Flow" per sh 10.25 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 3.59 4.23 3.62 3.85 4.10 Earnings per sh A 5.00 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 2.39 2.51 2.63 Div'd Decl'd per sh B | |||
* 3.05 5.08 3.44 4.28 6.11 8.89 8.88 9.83 6.19 5.07 5.74 6.45 7.75 8.68 9.37 9.98 11.79 12.50 12.95 Cap'I Spending per sh 11.25 20.85 19.93 21.32 23.08 23.73 25.17 26.33 27.49 28.33 30.33 31.37 32.98 34.37 36.44 35.38 37.17 38.60 40.20 Book Value per sh c 46.50 338.84 395.02 395.86 393.72 396.67 400.43 406.07 478.05 480.81 483.42 485.67 487.78 489.40 491.05 491.71 492.01 493.50 495.00 Common Shs Outst'g u 516.00 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 15.B 15.2 19.3 a*oldflg res are Avg Ann'I P/E Ratio 14.5 | * 3.05 5.08 3.44 4.28 6.11 8.89 8.88 9.83 6.19 5.07 5.74 6.45 7.75 8.68 9.37 9.98 11.79 12.50 12.95 Cap'I Spending per sh 11.25 20.85 19.93 21.32 23.08 23.73 25.17 26.33 27.49 28.33 30.33 31.37 32.98 34.37 36.44 35.38 37.17 38.60 40.20 Book Value per sh c 46.50 338.84 395.02 395.86 393.72 396.67 400.43 406.07 478.05 480.81 483.42 485.67 487.78 489.40 491.05 491.71 492.01 493.50 495.00 Common Shs Outst'g u 516.00 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 15.B 15.2 19.3 a*oldflg res are Avg Ann'I P/E Ratio 14.5 | ||
.69 .61 .66 .73 .70 .87 .79 .67 .85 .75 .88 .81 .84 .BO .BO .96 Value Line Relative P/E Ratio .80 estln ates 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% 3.8% 3.5% 3.4% Avg Ann'I Div'd Yield 4.2% | .69 .61 .66 .73 .70 .87 .79 .67 .85 .75 .88 .81 .84 .BO .BO .96 Value Line Relative P/E Ratio .80 estln ates 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% 3.8% 3.5% 3.4% Avg Ann'I Div'd Yield 4.2% | ||
| Line 1,700: | Line 1,597: | ||
76 ,23 IP/ERATIO 17, gerailing:18.2) RELATIVE 101 DIV'D CON. EDISON NYSE-ED High: 52.9 49.3 46.3 IRECENT PRICE 51.0 62.7 66.0 64.0 Median: | 76 ,23 IP/ERATIO 17, gerailing:18.2) RELATIVE 101 DIV'D CON. EDISON NYSE-ED High: 52.9 49.3 46.3 IRECENT PRICE 51.0 62.7 66.0 64.0 Median: | ||
68.9 15.0 P/E RATIO 72.3 81.9 I | 68.9 15.0 P/E RATIO 72.3 81.9 I | ||
89.7 YLD 3.8%111 84.9 Target Price Range TIMELINESS 3 Raised 312/18 Low: 43.1 34.1 32.6 41.5 48.6 53.6 54.2 52.2 56.9 63.5 72.1 73.7 2021 2022 2023 SAFETY 1 New 7/27/90 LEGENDS 120 | 89.7 YLD 3.8%111 84.9 Target Price Range TIMELINESS 3 Raised 312/18 Low: 43.1 34.1 32.6 41.5 48.6 53.6 54.2 52.2 56.9 63.5 72.1 73.7 2021 2022 2023 SAFETY 1 New 7/27/90 LEGENDS 120 100 TECHNICAL 4. Raised 5/18118 | ||
100 TECHNICAL 4. Raised 5/18118 | |||
.50 (1.00 = Market) | .50 (1.00 = Market) | ||
- ~i~i~:d ~vi1~,~~!sr ~~le | - ~i~i~:d ~vi1~,~~!sr ~~le | ||
... | ... | ||
* Relative ~rice Strength 0 , | * Relative ~rice Strength 0 , | ||
1111 | 1111 | ||
* 1 111 ---- ***** | * 1 111 ---- ***** | ||
.... ---- . 80 BETA | .... ---- . 80 BETA | ||
~t~~:/:,~a indicates recession _...(,'j'il* .... | ~t~~:/:,~a indicates recession _...(,'j'il* .... | ||
V' | V' | ||
"(11**1,11,11, 111111111" | "(11**1,11,11, 111111111" | ||
***II* 64 | ***II* 64 | ||
.tU~l-23 l't(UJt:\, IIUNl:l | .tU~l-23 l't(UJt:\, IIUNl:l | ||
.... 48 | .... 48 | ||
--~* | --~* | ||
Ann'I Total | Ann'I Total 1,1*'' 1 1 *11 | ||
1,1*'' 1 1 *11 | |||
...... It*p1*1** | ...... It*p1*1** | ||
Price Gain Return 32 High Low 85 (+10%l 70 *(-10% | |||
Price Gain Return | |||
32 High Low 85 (+10%l 70 *(-10% | |||
7% | 7% | ||
2% *-* *....***** ... .... ........... | 2% *-* *....***** ... .... ........... | ||
~ | ~ | ||
24 20 Insider Decisions J A SO ND J F M -** 16 to Buy 11 8 811 8 811 8 8 12 Options 0 0 0 2 2 0 812 0 to Soll 0 1 0 0 0 0 0 0 1 % TOT. RETURN 4/18 -8 | 24 20 Insider Decisions J A SO ND J F M -** 16 to Buy 11 8 811 8 811 8 8 12 Options 0 0 0 2 2 0 812 0 to Soll 0 1 0 0 0 0 0 0 1 % TOT. RETURN 4/18 -8 Institutional Decisions THIS VLAR!TH." | ||
Institutional Decisions THIS VLAR!TH." | |||
2Q2017 3Q2017 4Q2017 Percent 21 ,I I 1 yr. | 2Q2017 3Q2017 4Q2017 Percent 21 ,I I 1 yr. | ||
STOCK 4.6 INDEX 9.5 I- | STOCK 4.6 INDEX 9.5 I- | ||
| Line 1,793: | Line 1,676: | ||
toBuy tos,11 | toBuy tos,11 | ||
. 2Q2017 3Q2017 4Ql017 Percent 15 528 509 Hld's{000) 435858 442941 402762 531 494 531 shares 467 traded 101111111 5 | . 2Q2017 3Q2017 4Ql017 Percent 15 528 509 Hld's{000) 435858 442941 402762 531 494 531 shares 467 traded 101111111 5 | ||
I 1T'frt1r-t11,-,.,- | I 1T'frt1r-t11,-,.,- | ||
ilflttlm , | ilflttlm , | ||
| Line 1,801: | Line 1,683: | ||
17.6 32.2 IN~EX.5 : | 17.6 32.2 IN~EX.5 : | ||
25.8 _ | 25.8 _ | ||
68.8 | 68.8 l-:2=0,:,02,..,...,2=0=0=3.,..2=0=0'""4..,..,.,20=0=5-+=20=0=s,...,..,,2=00=7 2008 2009 2010 2011 2012 2013 2014 2015 2016 2i!!o~11~2~0~1=a+-2=0~1~9..j....,©;,.,V=AL~U=EL~IN=E=Pu=s.~LL-c-,J...1.-23.........I 25.32 30.24 31.15 29.18 32.22 32.63 27.88 34.84 33.84 34.10 32.49 33.66 33.45 34.20 Revenues per sh 36.50 7.86 8.11 7.34 7.58 8.49 8.68 6.80 8.56 9.11 9.40 9.20 10.01 11.15 11.70 "Cash Flow" per sh 13.25 2.76 3.60 3.03 3.39 4.02 4.14 3.71 3.98 4.13 4.10 3.71 4.22 4.80 5.00 Earnings per sh A 5.50 | ||
l-:2=0,:,02,..,...,2=0=0=3.,..2=0=0'""4..,..,.,20=0=5-+=20=0=s,...,..,,2=00=7 2008 2009 2010 2011 2012 2013 2014 2015 2016 2i!!o~11~2~0~1=a+-2=0~1~9..j....,©;,.,V=AL~U=EL~IN=E=Pu=s.~LL-c-,J...1.-23.........I 25.32 30.24 31.15 29.18 32.22 32.63 27.88 34.84 33.84 34.10 32.49 33.66 33.45 34.20 Revenues per sh 36.50 7.86 8.11 7.34 7.58 8.49 8.68 6.80 8.56 9.11 9.40 9.20 10.01 11.15 11.70 "Cash Flow" per sh 13.25 2.76 3.60 3.03 3.39 4.02 4.14 3.71 3.98 4.13 4.10 3.71 4.22 4.80 5.00 Earnings per sh A 5.50 | |||
' m m ~ m ~ ~ u ~ ~ ~ ~ ~ Div'd Decl'd per sh e | ' m m ~ m ~ ~ u ~ ~ ~ ~ ~ Div'd Decl'd per sh e | ||
* 4.40 8.07 7.43 10.35 9.85 10.84 9.80 7.81 7.83 7.62 9.83 11.29 11.50 15.05 15.00 Cap'l Spending per sh 11.75 62.30 50.40 49.51 49.85 50.84 51.14 58.04 58.54 57.81 57.74 58.62 59.63 61.05 62.35 Book Value per sh c 66.00 | * 4.40 8.07 7.43 10.35 9.85 10.84 9.80 7.81 7.83 7.62 9.83 11.29 11.50 15.05 15.00 Cap'l Spending per sh 11.75 62.30 50.40 49.51 49.85 50.84 51.14 58.04 58.54 57.81 57.74 58.62 59.63 61.05 62.35 Book Value per sh c 66.00 | ||
| Line 1,855: | Line 1,735: | ||
1 | 1 | ||
.*** 11 1 Price Gam Return ...~* ...... !1, L-.-.- .*-.. ,:1- | .*** 11 1 Price Gam Return ...~* ...... !1, L-.-.- .*-.. ,:1- | ||
.. ,1,* 11 1** 11(* | .. ,1,* 11 1** 11(* | ||
* 1 High 100 (+55%l 14% t..,._.,._.,.,,.,1;,..:=~=-6,...,:r;ffili,,11.!-:1-:-ril1,".'.F'.!!!Jlfl!.'.-F-...L-:.+--+--+--l--+-'--l--+--+--+--l--+--l-32 111 Low 75 (+15% 8% .-- ' '' 24 Insider Decisions * * .... * ...... *** -* **** ** ***-. ** ..... **** * "*, ........ -. 20 J JASON DJ F 16 to Buy O O O O O O O O O Options 2 O 1 O O 1 011 O to Sell 2 0 1 0 0 1 0 0 0 Institutional Decisions toBuy to Sell 2Q2017 299 236 3Q2017 274 258 4Q2017 Percent 278 shares 225 traded | * 1 High 100 (+55%l 14% t..,._.,._.,.,,.,1;,..:=~=-6,...,:r;ffili,,11.!-:1-:-ril1,".'.F'.!!!Jlfl!.'.-F-...L-:.+--+--+--l--+-'--l--+--+--+--l--+--l-32 111 Low 75 (+15% 8% .-- ' '' 24 Insider Decisions * * .... * ...... *** -* **** ** ***-. ** ..... **** * "*, ........ -. 20 J JASON DJ F 16 to Buy O O O O O O O O O Options 2 O 1 O O 1 011 O to Sell 2 0 1 0 0 1 0 0 0 Institutional Decisions toBuy to Sell 2Q2017 299 236 3Q2017 274 258 4Q2017 Percent 278 shares 225 traded 10 5 | ||
10 5 | |||
iii 15 * . . | iii 15 * . . | ||
I illlll c11tt'-.b!HIH--+----, | I illlll c11tt'-.b!HIH--+----, | ||
| Line 1,869: | Line 1,746: | ||
IN~~ ~ | IN~~ ~ | ||
24.3 ~ | 24.3 ~ | ||
12 Hld's(ODD) 290101 28837 4 267652 111 5 yr. 44.9 68.8 | 12 Hld's(ODD) 290101 28837 4 267652 111 5 yr. 44.9 68.8 | ||
'"'2='=0,;;;o;,;,;2~20='=0='=3..,=:-20:;;;o,;..,4,.,=;;2;,;.00;;;5;.+-,,2=0=0s="'""'2=0=07='J/ol2~00a 2009 2010 2011 2012 2013 2014 2015 2016 201~1~20~1=a-l-,,,20""1'""9,-1--.,;,.©v-A-LU=E-uN=E=pu=0~.L~LC~1,,h1,..,*2""3"""" | '"'2='=0,;;;o;,;,;2~20='=0='=3..,=:-20:;;;o,;..,4,.,=;;2;,;.00;;;5;.+-,,2=0=0s="'""'2=0=07='J/ol2~00a 2009 2010 2011 2012 2013 2014 2015 2016 201~1~20~1=a-l-,,,20""1'""9,-1--.,;,.©v-A-LU=E-uN=E=pu=0~.L~LC~1,,h1,..,*2""3"""" | ||
| Line 1,921: | Line 1,797: | ||
/-- -- .,1 1 1 | /-- -- .,1 1 1 | ||
1*' 11*" 1 | 1*' 11*" 1 | ||
----l---+----l--+ 40 50 Price Gain AnR~tJ~al ,---+----,1----+----,1---~,..--+-",,1..,11,l'+-~'*..,.~*"-".,._1"_1_,*1_,1_''1-''_"_ .. ,1,,-+-1_1_111_,*-+---1----+---1----1---1----1----,1-30 High 60 (+20%1 8% ,111 , .... I''" II *I, .. .,,, I I / / 25 Low 45 (-10% 1% -.. 20 Insider Decisions .,,, ******-**** * * * "Ill ii.* ,1 ,* *,.:***** 15 J J A S O N D J F *' 11'1!--*" ******" ' ***-,, *,"""''' *-***,,*'* "**, ,*" | |||
----l---+----l--+ 40 | |||
50 Price Gain AnR~tJ~al ,---+----,1----+----,1---~,..--+-",,1..,11,l'+-~'*..,.~*"-".,._1"_1_,*1_,1_''1-''_"_ .. ,1,,-+-1_1_111_,*-+---1----+---1----1---1----1----,1-30 High 60 (+20%1 8% ,111 , .... I''" II *I, .. .,,, I I / / 25 Low 45 (-10% 1% -.. 20 Insider Decisions .,,, ******-**** * * * "Ill ii.* ,1 ,* *,.:***** 15 J J A S O N D J F *' 11'1!--*" ******" ' ***-,, *,"""''' *-***,,*'* "**, ,*" | |||
* toBuy O O O O O O O O O 10 Options 340040047 to Soll 1 o o o o o o o o l---t---t---t---l----t---1----t---l----+---l----+ ---l----+----l % TOT. RETURN 3/lB 1-7.5 Institutional Decisions I THIS VLARJTll' 2Q2017 3Q2017 4Q2017 Percent 21 yr. sr~~K IN~~ '"' | * toBuy O O O O O O O O O 10 Options 340040047 to Soll 1 o o o o o o o o l---t---t---t---l----t---1----t---l----+---l----+ ---l----+----l % TOT. RETURN 3/lB 1-7.5 Institutional Decisions I THIS VLARJTll' 2Q2017 3Q2017 4Q2017 Percent 21 yr. sr~~K IN~~ '"' | ||
toBuy 117 96 86 shares 1 14 .,...,,-+--t;-t-H-tttt1"thh-*1tt:-'"-t-.---t----.-t----tt--,----,t--.rlT ,---t---t yr. 1 toSell 78 83 67 traded 7 11.,1 .,II 1* I ,lllmlllllmt I I ., ., htJllU 3 43 _5 24_3 1 Hld's(0001 45099 45123 39640 lllf11111111illllllllllllllJJJ,IJl!UU,lft111111lfllfllllt1111fff11 1111111111 111lll111111111ff-l 5yr. 75.1 68.8 1-,2""0~0"'"2,..2"'0'"'0;...3..,...,,.20""0'""4~2"""00'"'5--2"""00=5~2"""00=7-2/.!J.OOB 2009 2010 2011 2012 2013 2014 2015 2016 2017 2:..0'"'1.,..8+,,,20""'1""9-"'=,V.""1'. ,.,.LU"'"E'""LIN""E""'PU""B,.,L.,.,LC"",..,.1""-2""3 . -t 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 21.01 21.89 22.59 22.80 23.35 Revenues per sh 25.00 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 5.75 5.98 6.17 6.35 6. 60 "Cash Flow" per sh 7.50 | toBuy 117 96 86 shares 1 14 .,...,,-+--t;-t-H-tttt1"thh-*1tt:-'"-t-.---t----.-t----tt--,----,t--.rlT ,---t---t yr. 1 toSell 78 83 67 traded 7 11.,1 .,II 1* I ,lllmlllllmt I I ., ., htJllU 3 43 _5 24_3 1 Hld's(0001 45099 45123 39640 lllf11111111illllllllllllllJJJ,IJl!UU,lft111111lfllfllllt1111fff11 1111111111 111lll111111111ff-l 5yr. 75.1 68.8 1-,2""0~0"'"2,..2"'0'"'0;...3..,...,,.20""0'""4~2"""00'"'5--2"""00=5~2"""00=7-2/.!J.OOB 2009 2010 2011 2012 2013 2014 2015 2016 2017 2:..0'"'1.,..8+,,,20""'1""9-"'=,V.""1'. ,.,.LU"'"E'""LIN""E""'PU""B,.,L.,.,LC"",..,.1""-2""3 . -t 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 21.01 21.89 22.59 22.80 23.35 Revenues per sh 25.00 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 5.75 5.98 6.17 6.35 6. 60 "Cash Flow" per sh 7.50 | ||
| Line 1,978: | Line 1,851: | ||
"~==-***;",f~r!!:- *''-t--;;;:-t-----..;,l----:;:-:-t--+--l---;*"--..b,.-.-..-.f----t-- -+--t---+--t-2240 Insider Decisions "** ~- ....... l"!e*. | "~==-***;",f~r!!:- *''-t--;;;:-t-----..;,l----:;:-:-t--+--l---;*"--..b,.-.-..-.f----t-- -+--t---+--t-2240 Insider Decisions "** ~- ....... l"!e*. | ||
J J A S 0 N D J F l---+---l----+---1----l----1----l---+--+--+- -+--+--+--+--+--+---+-16 | J J A S 0 N D J F l---+---l----+---1----l----1----l---+--+--+- -+--+--+--+--+--+---+-16 | ||
.** e e* L-- | .** e e* L-- | ||
to Buy 0 0 0 0 0 0 0 0 0 Options 0 0 0 0 0 0 0 010 l---+--+---+--+---+--+---+--+---+--+---+ --+---+--+---+--+---+-12 to Sall 2 0 0 0 0 0 0 0 0 111;,,,., . ,: , | to Buy 0 0 0 0 0 0 0 0 0 Options 0 0 0 0 0 0 0 010 l---+--+---+--+---+--+---+--+---+--+---+ --+---+--+---+--+---+-12 to Sall 2 0 0 0 0 0 0 0 0 111;,,,., . ,: , | ||
% TOT. RETURN 3/18 ,-8 Institutional Decisions 1111 THIS VL ARITH." | % TOT. RETURN 3/18 ,-8 Institutional Decisions 1111 THIS VL ARITH." | ||
to Buy 2Q2017 139 3Q2017 116 4Q2017 Percent 127 shares 15 10 I. | to Buy 2Q2017 139 3Q2017 116 4Q2017 Percent 127 shares 15 10 I. | ||
.11,11, 1111-,1~, .... , .. | .11,11, 1111-,1~, .... , .. | ||
I II 1 yr. | I II 1 yr. | ||
| Line 2,046: | Line 1,915: | ||
o~~~~:/:ia indicates recession I/"'--.. ..... ~ *** 1r*11 | o~~~~:/:ia indicates recession I/"'--.. ..... ~ *** 1r*11 | ||
.... ,.. ,., .... ~oil r,4.. - | .... ,.. ,., .... ~oil r,4.. - | ||
64 48 Ann'I Total Price Gain Return ........... /.', ... ,1*11,,, 11111111 I High 75 (+35%1 11% | 64 48 Ann'I Total Price Gain Return ........... /.', ... ,1*11,,, 11111111 I High 75 (+35%1 11% | ||
..... .. *11' .. 1I 32 | ..... .. *11' .. 1I 32 1111111 Low 50 (-10% 2% .ui-~ 11 111 I | ||
1111111 Low 50 (-10% 2% .ui-~ 11 111 I | |||
. . .... 24 Insider Decisions J J A S 0 N D J F | . . .... 24 Insider Decisions J J A S 0 N D J F | ||
- ...... 11 | - ...... 11 | ||
| Line 2,061: | Line 1,926: | ||
STOCK | STOCK | ||
-4.9 11.4 INDEX 9.7 24.3 -- | -4.9 11.4 INDEX 9.7 24.3 -- | ||
to Soll Hld's(DDD) 56186 53930 45947 traded 10 | to Soll Hld's(DDD) 56186 53930 45947 traded 10 | ||
* II. lh I | * II. lh I 11111111111111m1111111111111 1111111111 11,111(1111 11111111111 1111111111 | ||
11111111111111m1111111111111 1111111111 11,111(1111 11111111111 1111111111 | |||
.II II 1111111111111111111m1 II II 5yr. 61.2 68.8 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 (£) VALUE LINE PUB. LLC 1, 1-23 | .II II 1111111111111111111m1 II II 5yr. 61.2 68.8 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 (£) VALUE LINE PUB. LLC 1, 1-23 | ||
.. .. 29.18 32.57 31.49 30.79 35.09 31.72 30.66 30.80 28.76 29.80 25.68 25.21 26.01 26.45 26.25 27.00 Revenues per sh 29.50 | .. .. 29.18 32.57 31.49 30.79 35.09 31.72 30.66 30.80 28.76 29.80 25.68 25.21 26.01 26.45 26.25 27.00 Revenues per sh 29.50 | ||
| Line 2,117: | Line 1,979: | ||
(+45%) Return 14% 1- l-:=j:==:J==j:==:J===t;:;;;:~~~~~~J::::'.=!=~~b!~'.'.: .. ... ...- .... ,.,.111-,1. J011il111~ ~ | (+45%) Return 14% 1- l-:=j:==:J==j:==:J===t;:;;;:~~~~~~J::::'.=!=~~b!~'.'.: .. ... ...- .... ,.,.111-,1. J011il111~ ~ | ||
...... ,-* I f===:f==::j:::==i:==:+/-==+/-==:+/-30 25 | ...... ,-* I f===:f==::j:::==i:==:+/-==+/-==:+/-30 25 | ||
.. -A" 20 | .. -A" 20 1,.L~o~wldef 35 J Insider Decisions B ~islc~(N~i'!!ll_..,: | ||
1,.L~o~wldef 35 J Insider Decisions B ~islc~(N~i'!!ll_..,: | |||
A s o N D J F M A 1 ****** *..-- ~ | A s o N D J F M A 1 ****** *..-- ~ | ||
5 | 5 | ||
| Line 2,131: | Line 1,991: | ||
toBuy O O O O O O 2 0 0 J-==:+:::'.::..:..+..::::.....J::!!L..:::...+...=:_+--J--+-_:+---.'.f:-:: r.a--k....,.,.J.,-.:w:~l--+--l---+--i----l-10 Options O O O O O O 11 o o .. "*, *" * ** * * **, "'" | toBuy O O O O O O 2 0 0 J-==:+:::'.::..:..+..::::.....J::!!L..:::...+...=:_+--J--+-_:+---.'.f:-:: r.a--k....,.,.J.,-.:w:~l--+--l---+--i----l-10 Options O O O O O O 11 o o .. "*, *" * ** * * **, "'" | ||
to Sell 1 o o 2 o o o o o 1---1---+---1---+---+--1----1---1----1---1----1 ---.=--1------i % TOT. RETURN st,e ,-7.5 Institutional Decisions toBuy to Sell 3Q2017 4Q2017 1Q2018 Percent 18 151 155 Hld'sjOOO 145781 124353 126569 ra e 155 138 188 h 184 ~ ~re; 1 2 - ~ 1111 1 6 | to Sell 1 o o 2 o o o o o 1---1---+---1---+---+--1----1---1----1---1----1 ---.=--1------i % TOT. RETURN st,e ,-7.5 Institutional Decisions toBuy to Sell 3Q2017 4Q2017 1Q2018 Percent 18 151 155 Hld'sjOOO 145781 124353 126569 ra e 155 138 188 h 184 ~ ~re; 1 2 - ~ 1111 1 6 | ||
'-- 1, .. 11. | '-- 1, .. 11. | ||
1 | 1 | ||
| Line 2,178: | Line 2,037: | ||
TIMELINESS 4 Lowereda/aO/lB SAFETY 1 5 | TIMELINESS 4 Lowereda/aO/lB SAFETY 1 5 | ||
Raised5/3/13 Lowered4/6/18 High: 51.7 42.9 | Raised5/3/13 Lowered4/6/18 High: 51.7 42.9 | ||
'-'-L~o~w~:~-36_._8~_26_.3~~22.3 | '-'-L~o~w~:~-36_._8~_26_.3~~22.3 LEGENDS 38.0 42.7 32.3 48.9 37.3 l:""T'"no_18__,.1___(~_~~i-,- i~~;l_U)-+-~_TE~--,r,i_o_.9,-16l_~~D_3--,.6°___[~ | ||
LEGENDS 38.0 42.7 32.3 48.9 37.3 l:""T'"no_18__,.1___(~_~~i-,- i~~;l_U)-+-~_TE~--,r,i_o_.9,-16l_~~D_3--,.6°___[~ | |||
54.7 45.9 l--+---4--+---l--+---l--+---4---1---4--+---4--+----l-120 | 54.7 45.9 l--+---4--+---l--+---l--+---4---1---4--+---4--+----l-120 | ||
~::d~vi1~t~~:.r ~~le 1--+---+--+----1--+----1--+---+---+---+--+---+--+---+-100 61.9 51.5 71.1 51.2 73.3 56.0 82.8 62.5 92.5 75.8 85.6 73.8 | ~::d~vi1~t~~:.r ~~le 1--+---+--+----1--+----1--+---+---+---+--+---+--+---+-100 61.9 51.5 71.1 51.2 73.3 56.0 82.8 62.5 92.5 75.8 85.6 73.8 | ||
| Line 2,196: | Line 2,053: | ||
llll11111111U1111111lllll11 illUul!uJJW11111111111111111 3 yr. | llll11111111U1111111lllll11 illUul!uJJW11111111111111111 3 yr. | ||
5 yr. | 5 yr. | ||
39.0 65.3 24.3 68.8 | 39.0 65.3 24.3 68.8 i-;2;:;,0~02~2='=0,:,;0'="3-r2""'0="0""4"T":'20:i:,o:ei:5.-h:2=oo""'s,..,..,.2=0=07::'lf'!,200s 2009 2010 2011 2012 2013 2014 2015 2:H/0~16,!II/J,!2l'!,Ou,&,17~2!:-,0,.,,1=s"'-=20""'1=9+-@"",v.=A""'Lu=-E""LIN=E""'Pu=s.....L,...,LC"",,1.,,1...,.-2"'"3-l 28.90 30.87 31.59 30.16 34.03 35.07 33.37 32.50 30.01 29.67 30.09 31.35 31.58 31.50 31.42 31.90 32.80 34.30 Revenues per sh 39.75 7.01 7.33 6.93 5.76 9.70 9.29 8.13 8.08 6.85 7.52 7.92 8.15 8.09 9.09 9.39 9.79 10.10 10.65 "Cash Flow" per sh 12.75 2.53 2.52 2.58 2.24 3.17 2.96 2.12 2.26 3.08 2.99 3.50 3.66 3.58 3.92 3.95 4.43 4.50 4.70 Earnings per sh A 5.50 1.63 1.73 1.83 1.93 2.03 2.10 2.10 2.10 2.10 2.10 2.67 2.23 2.33 2.44 2.56 2.70 2.86 3.02 Div'd Decl'd per sh e | ||
i-;2;:;,0~02~2='=0,:,;0'="3-r2""'0="0""4"T":'20:i:,o:ei:5.-h:2=oo""'s,..,..,.2=0=07::'lf'!,200s 2009 2010 2011 2012 2013 2014 2015 2:H/0~16,!II/J,!2l'!,Ou,&,17~2!:-,0,.,,1=s"'-=20""'1=9+-@"",v.=A""'Lu=-E""LIN=E""'Pu=s.....L,...,LC"",,1.,,1...,.-2"'"3-l 28.90 30.87 31.59 30.16 34.03 35.07 33.37 32.50 30.01 29.67 30.09 31.35 31.58 31.50 31.42 31.90 32.80 34.30 Revenues per sh 39.75 7.01 7.33 6.93 5.76 9.70 9.29 8.13 8.08 6.85 7.52 7.92 8.15 8.09 9.09 9.39 9.79 10.10 10.65 "Cash Flow" per sh 12.75 2.53 2.52 2.58 2.24 3.17 2.96 2.12 2.26 3.08 2.99 3.50 3.66 3.58 3.92 3.95 4.43 4.50 4.70 Earnings per sh A 5.50 1.63 1.73 1.83 1.93 2.03 2.10 2.10 2.10 2.10 2.10 2.67 2.23 2.33 2.44 2.56 2.70 2.86 3.02 Div'd Decl'd per sh e | |||
* 3.50 9.81 7.60 5.86 6.39 7.59 9.37 9.46 7.64 7.03 8.26 8.24 9.36 8.38 9.84 11.64 12.80 11.25 10.80 Cap'I Spending per sh 11.00 29.44 31.00 32.14 34.57 34.48 35.15 34.16 32.69 33.86 34.98 36.20 38.07 39.50 41.30 43.15 44.80 46.35 48.00 Book Value per sh c 54.00 91.26 91.29 91.79 99.08 99.96 100.49 100.89 101.43 108.77 109.25 109.74 110.18 110.57 110.98 111.34 111.75 112.00 112.25 Common Shs Outst'g 0 113.00 14.4 14.0 | * 3.50 9.81 7.60 5.86 6.39 7.59 9.37 9.46 7.64 7.03 8.26 8.24 9.36 8.38 9.84 11.64 12.80 11.25 10.80 Cap'I Spending per sh 11.00 29.44 31.00 32.14 34.57 34.48 35.15 34.16 32.69 33.86 34.98 36.20 38.07 39.50 41.30 43.15 44.80 46.35 48.00 Book Value per sh c 54.00 91.26 91.29 91.79 99.08 99.96 100.49 100.89 101.43 108.77 109.25 109.74 110.18 110.57 110.98 111.34 111.75 112.00 112.25 Common Shs Outst'g 0 113.00 14.4 14.0 | ||
* 15.8 19.2 13.7 14.9 16.1 13.7 12.6 14.6 14.3 15.3 15.9 16.0 18.7 19.3 Bold fig res are Avg Ann I P/E Ratio 15.0 | * 15.8 19.2 13.7 14.9 16.1 13.7 12.6 14.6 14.3 15.3 15.9 16.0 18.7 19.3 Bold fig res are Avg Ann I P/E Ratio 15.0 | ||
| Line 2,234: | Line 2,089: | ||
Low: | Low: | ||
31.3 25.5 27.7 15.4 13.5 17.5 21.3 24.3 27.4 29.0 33.0 35.3 42.4 39.0 2021 2022 2023 SAFETY 2 Raised 5/4/12 LEGENDS TECHNICAL 5 Lowered 4/20/18 -. . . . ~i~e~ i"i1;1~1!sf ~~te Relatwe Price Strength 80 60 BETA .65 (1.00 = Market) | 31.3 25.5 27.7 15.4 13.5 17.5 21.3 24.3 27.4 29.0 33.0 35.3 42.4 39.0 2021 2022 2023 SAFETY 2 Raised 5/4/12 LEGENDS TECHNICAL 5 Lowered 4/20/18 -. . . . ~i~e~ i"i1;1~1!sf ~~te Relatwe Price Strength 80 60 BETA .65 (1.00 = Market) | ||
O~~~~~/:!a indicates recession - ... 50 | O~~~~~/:!a indicates recession - ... 50 11111111*1 "U"l-23 t'KUJtl.llUN::i Ann'! Total - u.or 1*,,111 111 , | ||
40 I / 30 High Price Gain Return ,. ,1 111111 ., ' 25 50 9% | |||
11111111*1 "U"l-23 t'KUJtl.llUN::i Ann'! Total - u.or 1*,,111 111 , | |||
40 | |||
I / 30 High Price Gain Return ,. ,1 111111 ., ' 25 50 9% | |||
Low 35 Insider Decisions | Low 35 Insider Decisions | ||
(+20%1 | (+20%1 | ||
| Line 2,250: | Line 2,101: | ||
2Q2017 3Q2017 4Q2017 Percent 21 I 11 I I I 1yr. | 2Q2017 3Q2017 4Q2017 Percent 21 I 11 I I I 1yr. | ||
STOCK | STOCK | ||
-6.0 INDEX 9.7 | -6.0 INDEX 9.7 11~~~[111 ]~~~1111~~ij~l l1~~~ijl ~ 1 | ||
11~~~[111 ]~~~1111~~ij~l l1~~~ijl ~ 1 | |||
* to Buy to Soll 147 112 122 118 136 shares 91 traded 14 11*'' 11 11 3yr. 19.9 24.3 -- | * to Buy to Soll 147 112 122 118 136 shares 91 traded 14 11*'' 11 11 3yr. 19.9 24.3 -- | ||
7 II 5yr. 55.5 68.8 Hld'sJOOO) 88988 88359 81125 111111111111 2002 2003 2004 2005F 2006 2007 2012 2013 2014 2015 2016 2017 2018 2019 rs, VALUE LINE PUB. LLC 1-23 | 7 II 5yr. 55.5 68.8 Hld'sJOOO) 88988 88359 81125 111111111111 2002 2003 2004 2005F 2006 2007 2012 2013 2014 2015 2016 2017 2018 2019 rs, VALUE LINE PUB. LLC 1-23 | ||
| Line 2,302: | Line 2,151: | ||
~u,n-23 rt<uJt:i; 11uN:; - .,,.:--,_,,,.,... 11 o * *** * * *** | ~u,n-23 rt<uJt:i; 11uN:; - .,,.:--,_,,,.,... 11 o * *** * * *** | ||
* 40 1 | * 40 1 | ||
Price Gain An~~tJ~a 1---1---l---1---l---l--..,,e.l=-'~~----+.:irn:;::;;:pill!*ii t:'i:."::"'"1'.11'.!~11 '..::"1---l---*-l-*_::*.:.*:.:**:4:-"'.--l---l---l---l--30 | Price Gain An~~tJ~a 1---1---l---1---l---l--..,,e.l=-'~~----+.:irn:;::;;:pill!*ii t:'i:."::"'"1'.11'.!~11 '..::"1---l---*-l-*_::*.:.*:.:**:4:-"'.--l---l---l---l--30 High 50 (+10%) 6% ........ , ...,, .... ,, ' ... ., '* 25 Low 45 (Nil) 3% ,,, .... ,..... ..11*' .:;'.., .;;,,,.* ~ ' 20 Insider Decisions _. _.,. *, -* 15 J J A S O N D J F ****_ -.... ********* -.. ****** -** -.....*. 00 Ii to Buy O O O 1 0 0 0 0 0 "** " ** *.,. ***** " 10 | ||
High 50 (+10%) 6% ........ , ...,, .... ,, ' ... ., '* 25 Low 45 (Nil) 3% ,,, .... ,..... ..11*' .:;'.., .;;,,,.* ~ ' 20 Insider Decisions _. _.,. *, -* 15 J J A S O N D J F ****_ -.... ********* -.. ****** -** -.....*. 00 | |||
Ii to Buy O O O 1 0 0 0 0 0 "** " ** *.,. ***** " 10 | |||
: 10. * - | : 10. * - | ||
Options O O O O O O o O12 tos,n OO 1 0 0 1 1 0 0 1-------------+--+----+--+-------- ----------1 %TOT.RETURN3/18 - 7 ,5 Institutional Decisions I THIS VLARITH." | Options O O O O O O o O12 tos,n OO 1 0 0 1 1 0 0 1-------------+--+----+--+-------- ----------1 %TOT.RETURN3/18 - 7 ,5 Institutional Decisions I THIS VLARITH." | ||
| Line 2,314: | Line 2,159: | ||
3 yr. | 3 yr. | ||
5 yr. | 5 yr. | ||
STOCK 5.6 44.5 79.4 INDEX 9.7 24.3 68.8 | STOCK 5.6 44.5 79.4 INDEX 9.7 24.3 68.8 l-:2=0"='02.,.,..,2=0=0=3T"2=0=0,...,.4-r-=20=0=5--2=oo=s,...,...,,2"'"00=7 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUELINEPUB.LLC 1-23 23.89 19.90 20.84 23.86 24.16 23.40 | ||
l-:2=0"='02.,.,..,2=0=0=3T"2=0=0,...,.4-r-=20=0=5--2=oo=s,...,...,,2"'"00=7 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUELINEPUB.LLC 1-23 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 21.72 21.90 22.46 22.55 22.90 Revenues per sh 25.25 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 4.56 5.04 5.47 5.90 6.15 "Cash Flow" per sh 7.25 | * 24.69 21.08 21.38 21.90 20.76 21.92 23.11 21.72 21.90 22.46 22.55 22.90 Revenues per sh 25.25 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 4.56 5.04 5.47 5.90 6.15 "Cash Flow" per sh 7.25 | ||
.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 2.10 2.21 2.30 2.45 2.55 Earnings per sh A 3.00 1.13 .75 .81 .85 .88 .91 .94 .97 1.00 1.03 1.07 1.11 1.20 1.28 1.36 1.44 1.52 1.60 Div'd Decl'd per sh e | .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 2.10 2.21 2.30 2.45 2.55 Earnings per sh A 3.00 1.13 .75 .81 .85 .88 .91 .94 .97 1.00 1.03 1.07 1.11 1.20 1.28 1.36 1.44 1.52 1.60 Div'd Decl'd per sh e | ||
| Line 2,380: | Line 2,223: | ||
10/9/2017 $ 43.46 $ 41.84 $ 43.05 Est '15-'17 to '21-'23 6.50% 6.00% | 10/9/2017 $ 43.46 $ 41.84 $ 43.05 Est '15-'17 to '21-'23 6.50% 6.00% | ||
10/16/2017 $ 43.97 $ 42.78 $ 43.87 10/23/2017 $ 43.95 $ 42.72 $ 43.75 2017 2018 2019 '21 to '23 10/30/2017 $ 44.39 $ 42.88 $ 43.83, $ 1.26 $ 1.34 $ 1.42 $ 1.66 11/6/2017 $ 44.29 $ 43.51 $ 43.68 Source: June 15, 2018; Value-Line 11/13/2017 $ 45.55 $ 43.69 $ 44.40 11/20/2017 $ 44.49 $ 44.01 $ 44.22 11/27/2017 $ 45.38 $ 44.11 $ 44.83 NYSE:LNT Mean 12/4/2017 $ 45.22 $ 43.96 $ 44.94 LT Growth(%) 5.91 6.00 6.00 5.73 0.13 3 12/11/2017 $ 45.10 $ 43.56 $ 44.43 Source: SNL/S&P Global 12/18/2017 $ 44.37 $ 42.18 $ 42.50 12/25/2017 $ 42.97 $ 42.18 $ 42.61 --- - ------- -- ---- - - - - - - - - - ------ | 10/16/2017 $ 43.97 $ 42.78 $ 43.87 10/23/2017 $ 43.95 $ 42.72 $ 43.75 2017 2018 2019 '21 to '23 10/30/2017 $ 44.39 $ 42.88 $ 43.83, $ 1.26 $ 1.34 $ 1.42 $ 1.66 11/6/2017 $ 44.29 $ 43.51 $ 43.68 Source: June 15, 2018; Value-Line 11/13/2017 $ 45.55 $ 43.69 $ 44.40 11/20/2017 $ 44.49 $ 44.01 $ 44.22 11/27/2017 $ 45.38 $ 44.11 $ 44.83 NYSE:LNT Mean 12/4/2017 $ 45.22 $ 43.96 $ 44.94 LT Growth(%) 5.91 6.00 6.00 5.73 0.13 3 12/11/2017 $ 45.10 $ 43.56 $ 44.43 Source: SNL/S&P Global 12/18/2017 $ 44.37 $ 42.18 $ 42.50 12/25/2017 $ 42.97 $ 42.18 $ 42.61 --- - ------- -- ---- - - - - - - - - - ------ | ||
S.75 --- 6.75 1/1/2018 $ 42.72 1/8/2018 $ 41.58 1/15/2018 $ 40.17 | S.75 --- 6.75 1/1/2018 $ 42.72 1/8/2018 $ 41.58 1/15/2018 $ 40.17 40.92 39.49 39.33 41.08 39.53 39.41 l | ||
6.50 6.50 1/22/2018 $ 40.54 $ 39.45 $ 40.30 1/29/2018 $ 40.18 $ 38.46 $ 38.91 2/5/2018 $ 39.34 $ 36.84 $ 38.42 G.25 \ 6.25 2/12/2018 $ 39.81 $ 37.89 $ 39.75 2/19/2018 $ 39.70 $ 38.01 $ 39.42 fe 2/26/2018 $ 39.82 $ 37.85 $ 38.22 Cl 6.00 ' 6.00 3/5/2018 $ 38.99 $ 37.91 $ 38.71 3/12/2018 $ 40.22 $ 38.75 $ 40.13 S.7S 5.75 3/19/2018 $ 40.58 $ 39.38 $ 39.45 3/26/2018 $ 41.04 $ 39.43 $ 40.86 4/2/2018 $ 41.45 $ 40.34 $ 41.02 5.50 liSO 4/9/2018 $ 41.36 $ 40.38 $ 41.11 4/16/2018 $ 42.30 $ 41.23 $ 41.54 I 4/23/2018 $ 43.13 $ 41.45 $ 43.06 :~.--- -.--~---, ,....._, | |||
40.92 39.49 39.33 | |||
41.08 39.53 39.41 l | |||
6.50 6.50 1/22/2018 $ 40.54 $ 39.45 $ 40.30 1/29/2018 $ 40.18 $ 38.46 $ 38.91 2/5/2018 $ 39.34 $ 36.84 $ 38.42 G.25 \ 6.25 2/12/2018 $ 39.81 $ 37.89 $ 39.75 2/19/2018 $ 39.70 $ 38.01 $ 39.42 fe 2/26/2018 $ 39.82 $ 37.85 $ 38.22 Cl 6.00 ' 6.00 3/5/2018 $ 38.99 $ 37.91 $ 38.71 | |||
3/12/2018 $ 40.22 $ 38.75 $ 40.13 S.7S 5.75 3/19/2018 $ 40.58 $ 39.38 $ 39.45 3/26/2018 $ 41.04 $ 39.43 $ 40.86 4/2/2018 $ 41.45 $ 40.34 $ 41.02 5.50 liSO 4/9/2018 $ 41.36 $ 40.38 $ 41.11 4/16/2018 $ 42.30 $ 41.23 $ 41.54 I 4/23/2018 $ 43.13 $ 41.45 $ 43.06 :~.--- -.--~---, ,....._, | |||
4/30/2018 $ 43.47 $ 42.04 $ 43.27 S.25 | 4/30/2018 $ 43.47 $ 42.04 $ 43.27 S.25 | ||
~ ~ ~ ~ -~ ~ ~ ~ | ~ ~ ~ ~ -~ ~ ~ ~ | ||
~ ~ ~ | ~ ~ ~ | ||
-r--i | -r--i | ||
~ ~ ~ ~'b ..!tJ ~q;. | ~ ~ ~ ~'b ..!tJ ~q;. | ||
5.25 5/7/2018 $ 43.29 5/14/2018 $ 41.78 | 5.25 5/7/2018 $ 43.29 5/14/2018 $ 41.78 41.02 40.30 41.66 40.57 | ||
41.02 40.30 | |||
41.66 40.57 | |||
~ ./ <JI° ~.:I ,,~ ',, ',~# '~l~ 'i~ | ~ ./ <JI° ~.:I ,,~ ',, ',~# '~l~ 'i~ | ||
~ ~ ~ | ~ ~ ~ | ||
| Line 2,412: | Line 2,238: | ||
iii' | iii' | ||
.;,~ | .;,~ | ||
.f | .f 5/21/2018 $ 40.94 $ 40.11 $ 40.79 0,1~ | ||
5/21/2018 $ 40.94 $ 40.11 $ 40.79 0,1~ | |||
5/28/2018 $ 41.81 $ 40.47 $ 40.63 6/4/2018 $ 40.76 $ 38.99 $ 39.23 - L T Growth - LT Growth 6/11/2018 $ 40.08 $ 38.22 $ 39.96 6/18/2018 $ 41.28 $ 39.86 $ 41.09 6/25/2018 $ 42.78 $ 41.07 $ 42.32 7/2/2018 $ 43.42 $ 42.15 $ 43.41 Mimmum $ 36.84 $ 38.22 Maximum $ 45.55 $ 44.94 Mean $ 41.56 Source: l'ahooFmance, July 18, 2018 | 5/28/2018 $ 41.81 $ 40.47 $ 40.63 6/4/2018 $ 40.76 $ 38.99 $ 39.23 - L T Growth - LT Growth 6/11/2018 $ 40.08 $ 38.22 $ 39.96 6/18/2018 $ 41.28 $ 39.86 $ 41.09 6/25/2018 $ 42.78 $ 41.07 $ 42.32 7/2/2018 $ 43.42 $ 42.15 $ 43.41 Mimmum $ 36.84 $ 38.22 Maximum $ 45.55 $ 44.94 Mean $ 41.56 Source: l'ahooFmance, July 18, 2018 | ||
| Line 2,434: | Line 2,258: | ||
69.98 70.06 | 69.98 70.06 | ||
$ 67.56 | $ 67.56 | ||
$ 67.88 | $ 67.88 69.98 68.58 t | ||
69.98 68.58 t | |||
~ | ~ | ||
!:; | !:; | ||
| Line 2,445: | Line 2,266: | ||
79 .40 77.50 | 79 .40 77.50 | ||
$ 75.98 | $ 75.98 | ||
$ 73.76 | $ 73.76 77.78 74.49 | ||
77.78 74.49 | |||
//////~///~//////# | //////~///~//////# | ||
5/21/2018 $ 76.15 $ 74.28 $ 76.00 Dato 5/28/2018 $ 78.12 $ 75.53 $ 76.12 6/4/2018 $ 76.56 $ 72.78 $ 73.11 - LT Growth - LT Growth 6/11/2018 $ 73.28 $ 70.46 $ 73.11 6/18/2018 $ 76.65 $ 73.06 $ 76.31 6/25/2018 $ 78.62 $ 76.39 $ 77.41 7/2/2018 $ 79.50 $ 76.97 $ 79.45 M1rumwn $ 66.64 $ 68.08 Maximwn $ 81.24 $ 80.21 Mean $ 74.78 Source: YahooFmance, July 18, 2018 | 5/21/2018 $ 76.15 $ 74.28 $ 76.00 Dato 5/28/2018 $ 78.12 $ 75.53 $ 76.12 6/4/2018 $ 76.56 $ 72.78 $ 73.11 - LT Growth - LT Growth 6/11/2018 $ 73.28 $ 70.46 $ 73.11 6/18/2018 $ 76.65 $ 73.06 $ 76.31 6/25/2018 $ 78.62 $ 76.39 $ 77.41 7/2/2018 $ 79.50 $ 76.97 $ 79.45 M1rumwn $ 66.64 $ 68.08 Maximwn $ 81.24 $ 80.21 Mean $ 74.78 Source: YahooFmance, July 18, 2018 | ||
| Line 2,461: | Line 2,279: | ||
10/2/2017 $ 58.90 $ 57.67 $ 58.78 Past 5 Years 0.50% 2.00% | 10/2/2017 $ 58.90 $ 57.67 $ 58.78 Past 5 Years 0.50% 2.00% | ||
10/9/2017 $ 60.74 $ 58.80 $ 60.41 Est '15-'17 to '21-'23 7.50% 5.50% | 10/9/2017 $ 60.74 $ 58.80 $ 60.41 Est '15-'17 to '21-'23 7.50% 5.50% | ||
10/16/2017 $ 61.74 $ 60.13 $ 61.56 10/23/2017 $ 61.96 $ 60.52 $ 61.80 2017 2018 2019 '21 to '23 10/30/2017 $ 62.83 $ 61.48 $ 62.19 $ 1.78 $ 1.85 $ 1.94 $ 2.35 11/6/2017 $ 63.15 $ 61.95 $ 62.48 Source: June 15, 2018; Value-Line 11/13/2017 $ 64.89 $ 62.54 $ 63.30 11/20/2017 $ 63.66 $ 62.62 $ 62.98 11/27/2017 $ 64.36 $ 62.96 $ 63.75 NYSE:AEE Mean 12/4/2017 $ 64.02 $ 62.06 $ 63.19 LT Growth(%) 6.57 6.62 7.10 6.00 0.45 3 12/11/2017 $ 63.71 $ 60.32 $ 60.94 Source: SNL/S&P Global 12/18/2017 $ 61.22 $ 58.29 $ 58.69 12/25/2017 $ 59.44 $ 58.28 $ 58.99 1/1/2018 $ 59.03 $ 57.23 $ 57.39 6.70 - -------- - - 6.70 1/8/2018 $ 58.09 $ 55.42 $ 55.52 1/15/2018 $ 55.94 $ 54.83 $ 55.16 6.60 B.60 1/22/2018 $ 57.09 $ 55.26 $ 56.92 1/29/2018 $ 56.74 $ *54.77 $ 54.89 2/5/2018 $ 55.72 $ 51.89 $ 55.42 B.5<J 6.50 2/12/2018. $ 56.85 $ 54.32 $ 56.32 2/19/2018 $ 56.39 $ 54.23 $ 56.35 I 2/26/2018 $ 56.46 3/5/2018 $ 55.32 | 10/16/2017 $ 61.74 $ 60.13 $ 61.56 10/23/2017 $ 61.96 $ 60.52 $ 61.80 2017 2018 2019 '21 to '23 10/30/2017 $ 62.83 $ 61.48 $ 62.19 $ 1.78 $ 1.85 $ 1.94 $ 2.35 11/6/2017 $ 63.15 $ 61.95 $ 62.48 Source: June 15, 2018; Value-Line 11/13/2017 $ 64.89 $ 62.54 $ 63.30 11/20/2017 $ 63.66 $ 62.62 $ 62.98 11/27/2017 $ 64.36 $ 62.96 $ 63.75 NYSE:AEE Mean 12/4/2017 $ 64.02 $ 62.06 $ 63.19 LT Growth(%) 6.57 6.62 7.10 6.00 0.45 3 12/11/2017 $ 63.71 $ 60.32 $ 60.94 Source: SNL/S&P Global 12/18/2017 $ 61.22 $ 58.29 $ 58.69 12/25/2017 $ 59.44 $ 58.28 $ 58.99 1/1/2018 $ 59.03 $ 57.23 $ 57.39 6.70 - -------- - - 6.70 1/8/2018 $ 58.09 $ 55.42 $ 55.52 1/15/2018 $ 55.94 $ 54.83 $ 55.16 6.60 B.60 1/22/2018 $ 57.09 $ 55.26 $ 56.92 1/29/2018 $ 56.74 $ *54.77 $ 54.89 2/5/2018 $ 55.72 $ 51.89 $ 55.42 B.5<J 6.50 2/12/2018. $ 56.85 $ 54.32 $ 56.32 2/19/2018 $ 56.39 $ 54.23 $ 56.35 I 2/26/2018 $ 56.46 3/5/2018 $ 55.32 53.47 53.08 54.03 53.99 a* | ||
53.47 53.08 | |||
54.03 53.99 a* | |||
!:i 6.40 6.40 3/12/2018 $ 55.64 $ 53.88 $ 55.49 3/19/2018 $ 55.96 $ 53.91 $ 54.01 6.30 6.30 3/26/2018 $ 56.79 $ 54.10 $ 56.63 4/2/2018 $ 57.92 $ 56.15 $ 57.13 6.W 6.20 | !:i 6.40 6.40 3/12/2018 $ 55.64 $ 53.88 $ 55.49 3/19/2018 $ 55.96 $ 53.91 $ 54.01 6.30 6.30 3/26/2018 $ 56.79 $ 54.10 $ 56.63 4/2/2018 $ 57.92 $ 56.15 $ 57.13 6.W 6.20 | ||
,~ | ,~ | ||
4/9/2018 $ 57.55 $ 55.01 $ 55.51 4/16/2018 $ 57.49 $ 55.67 $ 56.27 4/23/2018 $ 58.72 $ 56.30 $ 58.60 | 4/9/2018 $ 57.55 $ 55.01 $ 55.51 4/16/2018 $ 57.49 $ 55.67 $ 56.27 4/23/2018 $ 58.72 $ 56.30 $ 58.60 | ||
#'I, . #'., .,.....~,., | #'I, . #'., .,.....~,., | ||
6.10 -----~--- 6.10 4/30/2018 $ 59.18 5/7/2018 $ 58.98 | 6.10 -----~--- 6.10 4/30/2018 $ 59.18 5/7/2018 $ 58.98 57.65 58.44 58.90 58.54 | ||
57.65 58.44 | |||
58.90 58.54 | |||
.#,fl ;" ".;,'<f' | .#,fl ;" ".;,'<f' | ||
._'\ ,(\ | ._'\ ,(\ | ||
| Line 2,505: | Line 2,310: | ||
10/16/2017 ..$ 73.99 $ 72.52 $ 73.98 10/23/2017 $ 74.90 $ 72.53 $ 74.02 2017 2018 2019 '21 to '23 10/30/2017 .$ 74.92 $ 73.57 $ 74.08 $ 2.39 $ 2.51 $ 2.63 $ 3.05 11/6/2017 $ 75.84 $ 73.56 $ 74.78 Source: June 15, 2018; Value-Line 11/13/2017 $ 77.93 $ 74.70 $ 76.38 11/20/2017 $ 77.06 $ 76.02 $ 76.47 11/27/2017 $ 77.97 $ 76.45 $ 77.24 NYSE : AEP Mean 12/4/2017 $ 78.07 $ 75.86 $ 76.93 LT Growth(%) 5.92 6.00 6.00 5.76 0.11 8 12/1112017 $ 77.22 $ 75.77 $ 76.54 Source: SNL/S&P Global 12/18/2017 $ 76.91 $ 73.62 $ 73.65 12/25/2017 $ 74.00 $ 72.94 $ 73.57 ------ --~--~-- ------------------, 6.00 6.00 1/1/2018 $ 73.42 $ 70.31 $ 70.80 1/8/2018 $ 71.53 $ 67.23 $ 67.46 1/15/2018 $ 68.59 $ 67.11 $ 67.76 1/22/2018 $ 69.80 $ 68.04 $ 68.75 5.50 5.50 1/29/2018 $ 68.98 $ 67.52 $ 67.75 2/5/2018 $ 68.42 $ 63.32 $ 64.72 2/12/2018 $ 67.52 $ 64.19 $ 67.26 2/19/2018 $ 67.50 $ 65.43 2/26/2018 $ 67.76 $ 64.60 | 10/16/2017 ..$ 73.99 $ 72.52 $ 73.98 10/23/2017 $ 74.90 $ 72.53 $ 74.02 2017 2018 2019 '21 to '23 10/30/2017 .$ 74.92 $ 73.57 $ 74.08 $ 2.39 $ 2.51 $ 2.63 $ 3.05 11/6/2017 $ 75.84 $ 73.56 $ 74.78 Source: June 15, 2018; Value-Line 11/13/2017 $ 77.93 $ 74.70 $ 76.38 11/20/2017 $ 77.06 $ 76.02 $ 76.47 11/27/2017 $ 77.97 $ 76.45 $ 77.24 NYSE : AEP Mean 12/4/2017 $ 78.07 $ 75.86 $ 76.93 LT Growth(%) 5.92 6.00 6.00 5.76 0.11 8 12/1112017 $ 77.22 $ 75.77 $ 76.54 Source: SNL/S&P Global 12/18/2017 $ 76.91 $ 73.62 $ 73.65 12/25/2017 $ 74.00 $ 72.94 $ 73.57 ------ --~--~-- ------------------, 6.00 6.00 1/1/2018 $ 73.42 $ 70.31 $ 70.80 1/8/2018 $ 71.53 $ 67.23 $ 67.46 1/15/2018 $ 68.59 $ 67.11 $ 67.76 1/22/2018 $ 69.80 $ 68.04 $ 68.75 5.50 5.50 1/29/2018 $ 68.98 $ 67.52 $ 67.75 2/5/2018 $ 68.42 $ 63.32 $ 64.72 2/12/2018 $ 67.52 $ 64.19 $ 67.26 2/19/2018 $ 67.50 $ 65.43 2/26/2018 $ 67.76 $ 64.60 | ||
$ 67.37 | $ 67.37 | ||
$ 65.18 st | $ 65.18 st 5.00 5.00 3/5/2018 $ 66.72 $ 64.65 $ 65.65 3/12/2018 $ 67.92 $ 65.57 $ 67.81 3/19/2018 $ 68.34 $ 66.25 $ 66.39 3/26/2018 $ 69.24 $ 66.56 $ 68.59 ~-f,IJ I 4/2/2018 .$ 69.42 $ 67.69 $ 68.53 4/9/2018 $ 69.14 $ 66.46 $ 67.34 4/16/2018 $ 69.67 $ 67.42 4/23/2018 $ 70. 98 $ 68.19 4/30/2018 $ 70.81 $ 68.52 | ||
5.00 5.00 3/5/2018 $ 66.72 $ 64.65 $ 65.65 3/12/2018 $ 67.92 $ 65.57 $ 67.81 3/19/2018 $ 68.34 $ 66.25 $ 66.39 3/26/2018 $ 69.24 $ 66.56 $ 68.59 ~-f,IJ I 4/2/2018 .$ 69.42 $ 67.69 $ 68.53 4/9/2018 $ 69.14 $ 66.46 $ 67.34 4/16/2018 $ 69.67 $ 67.42 4/23/2018 $ 70. 98 $ 68.19 4/30/2018 $ 70.81 $ 68.52 | |||
$ 68.46 | $ 68.46 | ||
$ 70.55 | $ 70.55 | ||
| Line 2,530: | Line 2,333: | ||
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ | ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ | ||
5/7/2018 $ 79.39 | 5/7/2018 $ 79.39 | ||
* 5/14/2018 $ 77.18 5/21/2018 $ 76.39 | * 5/14/2018 $ 77.18 5/21/2018 $ 76.39 74.88 73.35 73.38 | ||
74.88 73.35 73.38 | |||
$ 76.83 | $ 76.83 | ||
$ 73.97 | $ 73.97 | ||
| Line 2,552: | Line 2,351: | ||
10/2/2017 $ 84.74 $ 83.52 $ 84.64 Past 5 Years 0.50% 2.50% | 10/2/2017 $ 84.74 $ 83.52 $ 84.64 Past 5 Years 0.50% 2.50% | ||
10/9/2017 $ 87.60 $ 84.69 $ 86.79 Est '15-'17 to '21-'23 5.50% 4.50%. | 10/9/2017 $ 87.60 $ 84.69 $ 86.79 Est '15-'17 to '21-'23 5.50% 4.50%. | ||
10/16/2017 $ 88.06 $ 86.42 $ 87.93 10/23/2017 $ 88.55 $ 86.71 $ 87.95 2017 2018 2019 '21 to '23 10/30/2017 $ 89.50 $ 87.56 $ 88.52 $ 3.49 $ 3.64 $ 3.80 $ 4.40 Il/6/2017 $ 89.74 $ 87.61 $ 88.89 Source: June 15, 2018; Value-Line I 1/13/2017 $ 91.80 $ 88.45 $ 88.52 Il/20/2017 $ 89.20 $ 88.29 $ 88.78 11/27/2017 $ 89.72 $ 88.19 $ 88.73 NYSE:DUK Mean 12/4/2017 $ 89.43 $ 87.45 $ 88.05 LT Growth (% l 4.21 4.50 5.00 .3.00 0.80 5 12/Il/2017 $ 88.39 $ 86.72 $ 87.84 Source: SNL/S&P Global 12/18/2017 $ 88.15 * $ 83.75 $ 84.17 12/25/2017 $ 84.58 $ 83.56 $ 84.11 4.75 - - - ---- ----- - - -- - - ------------~----- 4.75 1/1/2018 $ 84.42 $ 81.35 $ 81.94 1/8/2018 $ 82.31 $ 78.55 $ 78.90 1/15/2018 $, 79.27 $ 76.64 $ 76.82 4.50 4.50 1/22/2018 $ 79.22 $ *76.85 $ 78.83 1/29/2018 $ 78.65 $ 76.43 $ 76.53 2/5/2018 $ 77.59 $ 72.93 $ 76.10 4.25 4.25 2/12/2018 $ 77.30 $ 74:66 $ 76.70 2/19/2018 $ 77.30 $ 74.82 $ 77.22 'ie 4.00 4.00 2/26/2018 $ 79.63 $ 74.58 3/5/2018 $ 77.67 $ 74.87 | 10/16/2017 $ 88.06 $ 86.42 $ 87.93 10/23/2017 $ 88.55 $ 86.71 $ 87.95 2017 2018 2019 '21 to '23 10/30/2017 $ 89.50 $ 87.56 $ 88.52 $ 3.49 $ 3.64 $ 3.80 $ 4.40 Il/6/2017 $ 89.74 $ 87.61 $ 88.89 Source: June 15, 2018; Value-Line I 1/13/2017 $ 91.80 $ 88.45 $ 88.52 Il/20/2017 $ 89.20 $ 88.29 $ 88.78 11/27/2017 $ 89.72 $ 88.19 $ 88.73 NYSE:DUK Mean 12/4/2017 $ 89.43 $ 87.45 $ 88.05 LT Growth (% l 4.21 4.50 5.00 .3.00 0.80 5 12/Il/2017 $ 88.39 $ 86.72 $ 87.84 Source: SNL/S&P Global 12/18/2017 $ 88.15 * $ 83.75 $ 84.17 12/25/2017 $ 84.58 $ 83.56 $ 84.11 4.75 - - - ---- ----- - - -- - - ------------~----- 4.75 1/1/2018 $ 84.42 $ 81.35 $ 81.94 1/8/2018 $ 82.31 $ 78.55 $ 78.90 1/15/2018 $, 79.27 $ 76.64 $ 76.82 4.50 4.50 1/22/2018 $ 79.22 $ *76.85 $ 78.83 1/29/2018 $ 78.65 $ 76.43 $ 76.53 2/5/2018 $ 77.59 $ 72.93 $ 76.10 4.25 4.25 2/12/2018 $ 77.30 $ 74:66 $ 76.70 2/19/2018 $ 77.30 $ 74.82 $ 77.22 'ie 4.00 4.00 2/26/2018 $ 79.63 $ 74.58 3/5/2018 $ 77.67 $ 74.87 75.35 76.13 Cl 3/12/2018 $ 77.73 $ 76.06 $ 77.59 3.75 3.75 3/19/2018 $ 77.87 $ 75.03 $ 75.17 3/26/2018 $ 77.91 $ 75.23 $ 77.47 - | ||
75.35 76.13 | |||
Cl 3/12/2018 $ 77.73 $ 76.06 $ 77.59 3.75 3.75 3/19/2018 $ 77.87 $ 75.03 $ 75.17 3/26/2018 $ 77.91 $ 75.23 $ 77.47 - | |||
4/2/2018 $ 78.90 $ 76.57 $ 78.16 3.50 3.50 4/9/2018 $ 79.05 $ 75.96 $ 76.67 4/16/2018 $ 79.42 $ 76.80 $ 77.68 I | 4/2/2018 $ 78.90 $ 76.57 $ 78.16 3.50 3.50 4/9/2018 $ 79.05 $ 75.96 $ 76.67 4/16/2018 $ 79.42 $ 76.80 $ 77.68 I | ||
4/23/2018 $ 80.75 $ 77.57 $ 80.50 3.25 | 4/23/2018 $ 80.75 $ 77.57 $ 80.50 3.25 | ||
~ | ~ | ||
(\ | (\ | ||
*\ | *\ | ||
,:0 ...... ~ ...... ,..'I> ~ . | ,:0 ...... ~ ...... ,..'I> ~ . | ||
3.25 4/30/2018 $ 80.85 $ 78.82 5/7/2018 $ 80.13 $ 76.88 79.88 77.91 ~ ~ ...-t'-~' ~~ | |||
3.25 4/30/2018 $ 80.85 $ 78.82 5/7/2018 $ 80.13 $ 76.88 | |||
79.88 77.91 ~ ~ ...-t'-~' ~~ | |||
....... . s-"~ ~""' .;,.<f' ~....#""' . <ii~ | ....... . s-"~ ~""' .;,.<f' ~....#""' . <ii~ | ||
(;' | (;' | ||
| Line 2,590: | Line 2,377: | ||
~ 5.00 5.00 2/26/2018 $ 62.62 $ 59.04 $ 59.59 | ~ 5.00 5.00 2/26/2018 $ 62.62 $ 59.04 $ 59.59 | ||
!:; | !:; | ||
3/5/2018 $ 60.84 $ 58.80 $ 59.38 3/12/2018 $ 65.15 $ 59.12 $ 65.15 3/19/201.8 $ 65.27 $ 61.77 $ 62.16 4.00 4.00 3/26/2018 $ 63.78 $ 61.47 $ 63.66 4/2/2018 $ 64.11 $ 62.09 $ 63.38 4/9/2018 $ 63.86 $ 62.60 $ 63.44 4/16/2018 $ 65.82 4/23/2018 $ 66.60 | 3/5/2018 $ 60.84 $ 58.80 $ 59.38 3/12/2018 $ 65.15 $ 59.12 $ 65.15 3/19/201.8 $ 65.27 $ 61.77 $ 62.16 4.00 4.00 3/26/2018 $ 63.78 $ 61.47 $ 63.66 4/2/2018 $ 64.11 $ 62.09 $ 63.38 4/9/2018 $ 63.86 $ 62.60 $ 63.44 4/16/2018 $ 65.82 4/23/2018 $ 66.60 63.30 63.73 | ||
63.30 63.73 | |||
$ 64.12 | $ 64.12 | ||
$ 65.79 | $ 65.79 | ||
| Line 2,608: | Line 2,392: | ||
10/2/2017 $ 57.00 $ 55.30 $ 56.85 Past_ 5 Years 18.00% | 10/2/2017 $ 57.00 $ 55.30 $ 56.85 Past_ 5 Years 18.00% | ||
10/9/2017 $ 58.70 $ 56.85 $ 58.10 Est '15-'17 to '21-'23 4.50% 7.00% | 10/9/2017 $ 58.70 $ 56.85 $ 58.10 Est '15-'17 to '21-'23 4.50% 7.00% | ||
10/16/2017 $ 58.05 $ 56.00 $ 57.25 10/23/2017 $ 58.70 $ 56.75 $ 58.40 2017 2018 2019 '21 to '23 10/30/2017 $ 58.45 $ 55.45 $ 57.60 $. 1.32 $ 1.42 $ 1.52 $ 1.85 11/6/2017 $ 58.65 $ 57.25 $ 57.75 Source: Jnne 15, 2018; Value-Line 11/13/2017 $ 60.70 $ 57.50 $ 60.20 11/20/2017 $ 60.70 $ 59.15 $ 59.65 11/27/2017 $ 61.15 $ 59.30 $ 60.25 NYSE:EE Mean 12/4/2017 $ 61.10 $ 58.55 $ 58.90 LT Growth(%) 5.10 5.10 5.20 5.00 0.10 2 12/11/2017 $ 59.40 $ 57.98 $ 59.10 Source: SNL/S&P Global 12/18/2017 $ 59.45 $ 54.75 $ 55.15 12/25/2017 $ 55.60 $ 54.60 $ 55.35 1/1/2018 $ 55.75 $ 53.65 $ 54.25 S.00 8.00 1/8/2018 $ 55.10 $ 50.70 $ 51.05 1/15/2018 $ 52.15 $ 50.70 $ 51.65 1/22/2018 $ 52.30 $ 51.15 $ 51.60 1/29/2018 $ 52.38 $ 50.95 $ 5_1.05 7.00 7_oo 2/5/2018 $ 51.45 $ 48.15 $ 50.75 2/12/2018 $ 51.45 $ 49.70 $ 51.30 2/19/2018 $ 51.40 $ 49.65 $ 50.55 ie 2/26/2018 $ 51.35 $ 48.05 $ 48.60 ~ 6.00 6.00 3/5/2018 $ 49.60 $ 48.05 $ 48.50 I- | 10/16/2017 $ 58.05 $ 56.00 $ 57.25 10/23/2017 $ 58.70 $ 56.75 $ 58.40 2017 2018 2019 '21 to '23 10/30/2017 $ 58.45 $ 55.45 $ 57.60 $. 1.32 $ 1.42 $ 1.52 $ 1.85 11/6/2017 $ 58.65 $ 57.25 $ 57.75 Source: Jnne 15, 2018; Value-Line 11/13/2017 $ 60.70 $ 57.50 $ 60.20 11/20/2017 $ 60.70 $ 59.15 $ 59.65 11/27/2017 $ 61.15 $ 59.30 $ 60.25 NYSE:EE Mean 12/4/2017 $ 61.10 $ 58.55 $ 58.90 LT Growth(%) 5.10 5.10 5.20 5.00 0.10 2 12/11/2017 $ 59.40 $ 57.98 $ 59.10 Source: SNL/S&P Global 12/18/2017 $ 59.45 $ 54.75 $ 55.15 12/25/2017 $ 55.60 $ 54.60 $ 55.35 1/1/2018 $ 55.75 $ 53.65 $ 54.25 S.00 8.00 1/8/2018 $ 55.10 $ 50.70 $ 51.05 1/15/2018 $ 52.15 $ 50.70 $ 51.65 1/22/2018 $ 52.30 $ 51.15 $ 51.60 1/29/2018 $ 52.38 $ 50.95 $ 5_1.05 7.00 7_oo 2/5/2018 $ 51.45 $ 48.15 $ 50.75 2/12/2018 $ 51.45 $ 49.70 $ 51.30 2/19/2018 $ 51.40 $ 49.65 $ 50.55 ie 2/26/2018 $ 51.35 $ 48.05 $ 48.60 ~ 6.00 6.00 3/5/2018 $ 49.60 $ 48.05 $ 48.50 I-3/12/2018 $ 49.60 $ 48.25 $ 49.60 3/19/2018 $ 50.70 $ 48.85 $ 48.85 3/26/2018 $ 51.25 $ 48.80 $ 51.00 6.00 5.00 4/2/2018 $ 51.30 $ 49.60 $ 50.35 4/9/2018 $ 50.50 $ 48.50 $ 48.90 4/16/2018 $ 50.40 $ 48.90 $ 49.05 IL_____ | ||
3/12/2018 $ 49.60 $ 48.25 $ 49.60 3/19/2018 $ 50.70 $ 48.85 $ 48.85 3/26/2018 $ 51.25 $ 48.80 $ 51.00 6.00 5.00 4/2/2018 $ 51.30 $ 49.60 $ 50.35 4/9/2018 $ 50.50 $ 48.50 $ 48.90 4/16/2018 $ 50.40 $ 48.90 $ 49.05 IL_____ | |||
4/23/2018 $ 51.55 $ 49.05 $ 51.35 ,.oo ,.oo 4/30/2018 $ 56.90 $ 49.45 $ 55.05 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ | 4/23/2018 $ 51.55 $ 49.05 $ 51.35 ,.oo ,.oo 4/30/2018 $ 56.90 $ 49.45 $ 55.05 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ | ||
5/7/2018 $ 56.65 5/14/2018 $ 56.80 | 5/7/2018 $ 56.65 5/14/2018 $ 56.80 | ||
$ 54.50 | $ 54.50 | ||
$ 54.33 | $ 54.33 56.55 55.40 / / / / / / / / / / / / / ~ / / / ~"'"' (fi' 5/21/2018 $ 58.25 $ 55.20 $ 58.05 Dato 5/28/2018 $ 59.13 $ 57.65 $ 58.60 6/4/2018 $ 59.15 $. 55.60 $ 55.95 - LT Growth - LTGruwth 6/11/2018 $ 56.20 $ 54.75 $ 55.70 6/18/2018 $ 58.85 $ 55.80 $ 58.80 6/25/2018 $ 59.35 $ 57.70 $ 59.10 7/2/2018 $ 60.10 $ 58.25 $ 60.05 Mm1mum $ 48.05 $ 48.50 Maximum $ 61.15 $ 60.25 Mean $ 54.44 Source: l'ahooFmance, July 18, 2018 | ||
56.55 55.40 / / / / / / / / / / / / / ~ / / / ~"'"' (fi' 5/21/2018 $ 58.25 $ 55.20 $ 58.05 Dato 5/28/2018 $ 59.13 $ 57.65 $ 58.60 6/4/2018 $ 59.15 $. 55.60 $ 55.95 - LT Growth - LTGruwth 6/11/2018 $ 56.20 $ 54.75 $ 55.70 6/18/2018 $ 58.85 $ 55.80 $ 58.80 6/25/2018 $ 59.35 $ 57.70 $ 59.10 7/2/2018 $ 60.10 $ 58.25 $ 60.05 Mm1mum $ 48.05 $ 48.50 Maximum $ 61.15 $ 60.25 Mean $ 54.44 Source: l'ahooFmance, July 18, 2018 | |||
Schedule AHG - 4 18-KCPE-480-RTS IDACORP, Inc (IDA} | Schedule AHG - 4 18-KCPE-480-RTS IDACORP, Inc (IDA} | ||
| Line 2,632: | Line 2,410: | ||
10/16/2017 $ 92.26 $ 89.79 $ 91.68 10/23/2017 $ 93.22 $ 90.10 $ 93.18 2017 2018 2019 '21 to '23 10/30/2017 $ 93.79 $ 91.06 $ 92.71 $ 2.24 $ 2.40 $ 2.56 $ 3.05 11/6/2017 $ 95.57 $ 92.50 $ 95.17 Source: June is, 2018; Value-Line 11/13/2017 $ 98.43 $ 95.08 $ 97.23 11/20/2017 $ 97.98 $ 96.20 $ 96.55 11/27/2017 $ 100.04 $ 96.19 $ 98.23 NYSE:IDA Mean 12/4/2017 $ 99.03 $ 95.95 $ 97.16 LT Growth(%) 3.91 4.00 5.00 2.74 0.93 3 12/11/2017 $ 97.26 $ 93.92 $ 95.51 Source: SNL/S&P Global 12/18/2017 $ 96.13 $ 90.03 $ 90.66 12/25/2017 $ 92.43 $ 89.81 $ 91.36 --------~ | 10/16/2017 $ 92.26 $ 89.79 $ 91.68 10/23/2017 $ 93.22 $ 90.10 $ 93.18 2017 2018 2019 '21 to '23 10/30/2017 $ 93.79 $ 91.06 $ 92.71 $ 2.24 $ 2.40 $ 2.56 $ 3.05 11/6/2017 $ 95.57 $ 92.50 $ 95.17 Source: June is, 2018; Value-Line 11/13/2017 $ 98.43 $ 95.08 $ 97.23 11/20/2017 $ 97.98 $ 96.20 $ 96.55 11/27/2017 $ 100.04 $ 96.19 $ 98.23 NYSE:IDA Mean 12/4/2017 $ 99.03 $ 95.95 $ 97.16 LT Growth(%) 3.91 4.00 5.00 2.74 0.93 3 12/11/2017 $ 97.26 $ 93.92 $ 95.51 Source: SNL/S&P Global 12/18/2017 $ 96.13 $ 90.03 $ 90.66 12/25/2017 $ 92.43 $ 89.81 $ 91.36 --------~ | ||
5.25 - 5.25 1/1/2018 $ 91.40 $ 87.23 $ 87.69 1/8/2018 $ 88.31 $ 82.08 $ 83.32 1/15/2018 $ 84.70 $ 82.62 $ 83.86 5.00 5.00 1/22/2018 $ 86.74 $ 83.10 $ 86.07 1/29/2018 $ 86.57 $ 83.25 $ 83.39 2/5/2018 $ 84.32 $ 79.59 $ 83.57 4.75 4.75 2/12/2018 $ 85.53 $ 82.02 $ 85.27 2/19/2018 $ 85.05 $ 82.23 $ 84.98 ,:. | 5.25 - 5.25 1/1/2018 $ 91.40 $ 87.23 $ 87.69 1/8/2018 $ 88.31 $ 82.08 $ 83.32 1/15/2018 $ 84.70 $ 82.62 $ 83.86 5.00 5.00 1/22/2018 $ 86.74 $ 83.10 $ 86.07 1/29/2018 $ 86.57 $ 83.25 $ 83.39 2/5/2018 $ 84.32 $ 79.59 $ 83.57 4.75 4.75 2/12/2018 $ 85.53 $ 82.02 $ 85.27 2/19/2018 $ 85.05 $ 82.23 $ 84.98 ,:. | ||
!::j 2/26/2018 $ 85.25 $ 80.45 3/5/2018 $ 83.00 $ 80.29 | !::j 2/26/2018 $ 85.25 $ 80.45 3/5/2018 $ 83.00 $ 80.29 81.61 81.95 I | ||
81.61 81.95 I | |||
t.:J ,1_5(1 ,.so Gl 0 | t.:J ,1_5(1 ,.so Gl 0 | ||
~ | ~ | ||
| Line 2,654: | Line 2,429: | ||
- 12/11/2017 $ 63.33 $ 60.82 $ 61.60 Source: SNL/S&P Global 12/18/2017 $ 62.13 $ 58.48 $ 59.27 12/25/2017 $ 59.91 $ 58.66 $ 59.70 l.50 3.5() | - 12/11/2017 $ 63.33 $ 60.82 $ 61.60 Source: SNL/S&P Global 12/18/2017 $ 62.13 $ 58.48 $ 59.27 12/25/2017 $ 59.91 $ 58.66 $ 59.70 l.50 3.5() | ||
1/1/2018 $ 59.82 $ 57.00 $ 57.41 1/8/2018 $ 57.80 $ 55.33 $ 55.40 1/15/2018 $ 55.50 $ 53.01 $ 53.21 1 1/22/2018 $ 54.75 $ 53.13 $ | 1/1/2018 $ 59.82 $ 57.00 $ 57.41 1/8/2018 $ 57.80 $ 55.33 $ 55.40 1/15/2018 $ 55.50 $ 53.01 $ 53.21 1 1/22/2018 $ 54.75 $ 53.13 $ | ||
54.36 l.00 I 3.00 1/29/2018 $ 54.51 $ 52.71 52.86 | 54.36 l.00 I 3.00 1/29/2018 $ 54.51 $ 52.71 52.86 | ||
.2/5/2018 $ 53.35 $ 50.01 $ 52.13 2/12/2018 $ 52.61 $ 50.64 2/19/2018 $ 52.50 $ 50.89 | .2/5/2018 $ 53.35 $ 50.01 $ 52.13 2/12/2018 $ 52.61 $ 50.64 2/19/2018 $ 52.50 $ 50.89 52.27 52.50 | ||
52.27 52.50 | |||
.c | .c | ||
* 2.5D | * 2.5D | ||
'i I 2.51l 2/26/2018 $ 52.76 $ 50.54 $ 51.06 e I | 'i I 2.51l 2/26/2018 $ 52.76 $ 50.54 $ 51.06 e I | ||
,_Cl I 3/5/2018 $ 52.13 $ 50.46 $ 51.07 .... 2.00 I 2.00 3/12/2018 $ 52.07 $ 50.65 $ 51.90 I 3/19/2018 $ 53.31 $ 51.47 $ 51.52 I | ,_Cl I 3/5/2018 $ 52.13 $ 50.46 $ 51.07 .... 2.00 I 2.00 3/12/2018 $ 52.07 $ 50.65 $ 51.90 I 3/19/2018 $ 53.31 $ 51.47 $ 51.52 I | ||
3/26/2018 $ 54.19 $ 51.63 $ 53.80 4/2/2018 $ 54.51 $ 52.43 4/9/2018 $ 54.33 $ 52.74 | 3/26/2018 $ 54.19 $ 51.63 $ 53.80 4/2/2018 $ 54.51 $ 52.43 4/9/2018 $ 54.33 $ 52.74 53.89 53.27 1.51l I 1.51) 4/16/2018 $ 55.20 $ 53.45 $ 53.85 4/23/2018 $ 55.65 $ 53.72 $ 55.36 1.00 _ . r -I 1.00 4/30/2018 $ 55.80 $ 54.15 $ 55.53 ~ . ._q, | ||
53.89 53.27 1.51l I 1.51) 4/16/2018 $ 55.20 $ 53.45 $ 53.85 4/23/2018 $ 55.65 $ 53.72 $ 55.36 1.00 _ . r -I 1.00 4/30/2018 $ 55.80 $ 54.15 $ 55.53 ~ . ._q, | |||
~::, ~ ~ | ~::, ~ ~ | ||
-,,,#''I, | -,,,#''I, | ||
| Line 2,690: | Line 2,458: | ||
10/16/2017 $ 37.21 $ 36.62 $ 37.09 10/23/2017 $ 37.32 $ 36.35 $ 37.08 2017 2018 2019 '21 to '23 10/30/2017 $ 37.20 $ 35.60 $ 35.63 $ 1.27 $ 1.40 $ 1.54 $ 1.85 11/6/2017 $ 36.00 $ 34.93 $ 35.01 Source: June 15, 2018; Value-Line 11/13/2017 $ 36.01 $ 34.89 $ 35.20 11/20/2017 $ 35.27 $ 34.72 $ 34.90 11/27/2017 $ 36.00 $ 34.81 $ 35.23 NYSE:OGE Mean 12/4/2017 $ 35.67 $ 33.97 $ 34.46 LT Growth (%) 4.10 4.10 4.30 3.90 0.20 2 12/11/2017 $ 34.72 $ 33.47 $ 34.15 Source: SNL/S&P Global 12/18/2017 $ 34.40 $ 32.65 $ 33.01 12/25/2017 $ 33.20 $ 32.60 $ 32.91 1/1/2018 $ 33.07 $ 32.47 $ 32.50 7.0D - ----*---*--- - - - - - - - - - - - - - 7_00 1/8/2018 $ 32.84 $ 30.70 $ 30.74 1/15/2018 $ 31.78 $ 30.76 $ 31.42 1/22/2018 $ 32.54 $ 31.47 $ 32.14 1/29/2018 $ 32.36 $ 31.31 $ 31.35 6.00 6.00 2/5/2018 $ 31.54 $ 29.59 $ 30.39 2/12/2018 $ 31.66 $ 30.34 $ 31.56 2/19/2018 $ 33.06 $ 30.74 $ 32.95 "''§: | 10/16/2017 $ 37.21 $ 36.62 $ 37.09 10/23/2017 $ 37.32 $ 36.35 $ 37.08 2017 2018 2019 '21 to '23 10/30/2017 $ 37.20 $ 35.60 $ 35.63 $ 1.27 $ 1.40 $ 1.54 $ 1.85 11/6/2017 $ 36.00 $ 34.93 $ 35.01 Source: June 15, 2018; Value-Line 11/13/2017 $ 36.01 $ 34.89 $ 35.20 11/20/2017 $ 35.27 $ 34.72 $ 34.90 11/27/2017 $ 36.00 $ 34.81 $ 35.23 NYSE:OGE Mean 12/4/2017 $ 35.67 $ 33.97 $ 34.46 LT Growth (%) 4.10 4.10 4.30 3.90 0.20 2 12/11/2017 $ 34.72 $ 33.47 $ 34.15 Source: SNL/S&P Global 12/18/2017 $ 34.40 $ 32.65 $ 33.01 12/25/2017 $ 33.20 $ 32.60 $ 32.91 1/1/2018 $ 33.07 $ 32.47 $ 32.50 7.0D - ----*---*--- - - - - - - - - - - - - - 7_00 1/8/2018 $ 32.84 $ 30.70 $ 30.74 1/15/2018 $ 31.78 $ 30.76 $ 31.42 1/22/2018 $ 32.54 $ 31.47 $ 32.14 1/29/2018 $ 32.36 $ 31.31 $ 31.35 6.00 6.00 2/5/2018 $ 31.54 $ 29.59 $ 30.39 2/12/2018 $ 31.66 $ 30.34 $ 31.56 2/19/2018 $ 33.06 $ 30.74 $ 32.95 "''§: | ||
2/26/2018 $ 33.00 $ 30.85 $ 31.19 e Cl 5.0D 5.00 3/5/2018 $ 32.08 $ 30.76 $ 31.35 !:; | 2/26/2018 $ 33.00 $ 30.85 $ 31.19 e Cl 5.0D 5.00 3/5/2018 $ 32.08 $ 30.76 $ 31.35 !:; | ||
3/12/2018 $ 32.17 $ 31.14 $ 32.00 3/19/2018 $ 32.39 $ 31.38 $ 31.43 3/.26/2018 $ 32.83 $ 31.43 $ 32.77 *. 00 ,.oo 4/2/2018 $ 32.98 $ 31.94 $ 32.37 4/9/2018 $ 32.31 $ 31.49 $ 31.61 4/16/2018 $ 32.91 $ 31.69 $ 32.47 4/23/2018 $ 33.16 4/30/2018 $ 34.37 | 3/12/2018 $ 32.17 $ 31.14 $ 32.00 3/19/2018 $ 32.39 $ 31.38 $ 31.43 3/.26/2018 $ 32.83 $ 31.43 $ 32.77 *. 00 ,.oo 4/2/2018 $ 32.98 $ 31.94 $ 32.37 4/9/2018 $ 32.31 $ 31.49 $ 31.61 4/16/2018 $ 32.91 $ 31.69 $ 32.47 4/23/2018 $ 33.16 4/30/2018 $ 34.37 32.38 32.70 | ||
32.38 32.70 | |||
$ 32.91 | $ 32.91 | ||
$ 34.17 l.00 | $ 34.17 l.00 | ||
~ ~ ~ | ~ ~ ~ | ||
~ ~ | ~ ~ | ||
~ ~ | ~ ~ | ||
~ ~ | ~ ~ | ||
~ ~ | ~ ~ | ||
~ ~ ~ | ~ ~ ~ | ||
3.00 | 3.00 | ||
| Line 2,728: | Line 2,488: | ||
3/5/2018 $ 78.3) $ 75.21 $ 76.38 I- | 3/5/2018 $ 78.3) $ 75.21 $ 76.38 I- | ||
..I 5' 3/12/2018 $ 78.00 $ 75.96 $ 77.97 3/19/2018 $ 80.14 $ 77.40 $ 77.76 3/26/2018 $ 80.21 $ 77.73 $ 79.80 .f.fAJ 4.50 4/2/2018 $ 80.54 $ 78.~2 $ 79.75 4/9/2018 $ 80.37 $ 77.14 $ 78.14 4/16/2018 $ 80.73 $ 77.55 $ 78.02 4/23/2018 $ 81.85 $ 77.95 $ 81.61 4.0D 4.00 4/30/2018 $ 81.61 $ 78.24 $ 80.20 ...._"\ .(\ ,:'I ,:, !'o.'b ~'ti .....~ ~ ~ ~ ...._'b ...._ra. | ..I 5' 3/12/2018 $ 78.00 $ 75.96 $ 77.97 3/19/2018 $ 80.14 $ 77.40 $ 77.76 3/26/2018 $ 80.21 $ 77.73 $ 79.80 .f.fAJ 4.50 4/2/2018 $ 80.54 $ 78.~2 $ 79.75 4/9/2018 $ 80.37 $ 77.14 $ 78.14 4/16/2018 $ 80.73 $ 77.55 $ 78.02 4/23/2018 $ 81.85 $ 77.95 $ 81.61 4.0D 4.00 4/30/2018 $ 81.61 $ 78.24 $ 80.20 ...._"\ .(\ ,:'I ,:, !'o.'b ~'ti .....~ ~ ~ ~ ...._'b ...._ra. | ||
5/7/2018 $ 80.48 5/14/2018 $ 78.39 | 5/7/2018 $ 80.48 5/14/2018 $ 78.39 76.96 75.97 78.12 76.54 | ||
76.96 75.97 | |||
78.12 76.54 | |||
.J'(E' / .,,,#' ,~--~- ./' ../ / / ~,f-' , / | .J'(E' / .,,,#' ,~--~- ./' ../ / / ~,f-' , / | ||
...._"ti """" ...,.tti | ...._"ti """" ...,.tti | ||
| Line 2,752: | Line 2,506: | ||
I-3/12/2018 $ 40.09 $ 39.07 $ 40.05 3/19/2018 $ 41.06 $ 39.09 $ 39.11 3/26/2018 $ 40.76 $ 39.27 ~ 40.51 l.00 3,00 4/2/2018 $ 40.66 $ 39.56 $ 40.21 4/9/2018 $ 40.54 $ 39.18 $ 40.22 4/16/2018, $ 41.21 $ 40.07 $ 40.17 4/23/2018 $ 42.59 $ 40.15 $ 42.33 -, - - - - - - -- . - -------- -- --.-- ~,..-------, - -- 2.51) 4/30/2018 $ 42.93 $ 41.63 $ 42.76 2.5D | I-3/12/2018 $ 40.09 $ 39.07 $ 40.05 3/19/2018 $ 41.06 $ 39.09 $ 39.11 3/26/2018 $ 40.76 $ 39.27 ~ 40.51 l.00 3,00 4/2/2018 $ 40.66 $ 39.56 $ 40.21 4/9/2018 $ 40.54 $ 39.18 $ 40.22 4/16/2018, $ 41.21 $ 40.07 $ 40.17 4/23/2018 $ 42.59 $ 40.15 $ 42.33 -, - - - - - - -- . - -------- -- --.-- ~,..-------, - -- 2.51) 4/30/2018 $ 42.93 $ 41.63 $ 42.76 2.5D | ||
(:, "'I ,(lo | (:, "'I ,(lo | ||
,(', ,... "'lo ,., ,~ ~ ~ | ,(', ,... "'lo ,., ,~ ~ ~ | ||
'1~<6'"" <j._#' , / / #fl ,I''"' 'I'",# | '1~<6'"" <j._#' , / / #fl ,I''"' 'I'",# | ||
| Line 2,762: | Line 2,515: | ||
rt 'ii~ | rt 'ii~ | ||
~of' -v'# / ~I~ ~ | ~of' -v'# / ~I~ ~ | ||
5/21/2018 $ 41.92 $ 39.66 $ 41.87 | 5/21/2018 $ 41.92 $ 39.66 $ 41.87 0.ilt!I 5/28/2018 $ 42.93 $ 41.46 $ 42.27 6/4/2018 $ 42.41 $ 39.99 $ 40.21 - LT Growth - LT Growth 6/11/2018 $ 41.43 $ 39.60 $ 41.40 6/18/2018 $ 42.59 $ | ||
0.ilt!I 5/28/2018 $ 42.93 $ 41.46 $ 42.27 6/4/2018 $ 42.41 $ 39.99 $ 40.21 - LT Growth - LT Growth 6/11/2018 $ 41.43 $ 39.60 $ 41.40 6/18/2018 $ 42.59 $ | |||
* 41.12 $ 42.41 6/25/2018 $ 43.29 $ 42.39 $ 42.76 7/2/2018 $ 43.96 $ 42.47 $ 43.95 Mtmmum $ 39.02 $ 39.11 Maximum $ 50.11 $ 49.49 Mean $ 43.97 Source: I' ahooFmance, July 18, 2018 | * 41.12 $ 42.41 6/25/2018 $ 43.29 $ 42.39 $ 42.76 7/2/2018 $ 43.96 $ 42.47 $ 43.95 Mtmmum $ 39.02 $ 39.11 Maximum $ 50.11 $ 49.49 Mean $ 43.97 Source: I' ahooFmance, July 18, 2018 | ||
| Line 2,778: | Line 2,529: | ||
10/2/2017 $ 47.80 $ 46.86 $ 47-.39 Past 5 Years 5.00% 5.50% | 10/2/2017 $ 47.80 $ 46.86 $ 47-.39 Past 5 Years 5.00% 5.50% | ||
10/9/2017 $ 49.08 $ 47.37 $ 48.61 Est '15-'17 to '21-'23 5.50% 5.50% | 10/9/2017 $ 49.08 $ 47.37 $ 48.61 Est '15-'17 to '21-'23 5.50% 5.50% | ||
10/16/2017 $ 49.41 $ 48.26 $ 49.26 10/23/2017 $ 49.83 $ 48.56 $ 49.21 2017 2018 .2019 '21 to '23 10/30/2017 $ 49.92 $ 48.93 $ 49.59 $ 1.44 $ 1.52 $ 1.60 $ 1.90 11/6/2017 $ 50.57 $ 49.29 $ 50.20 Source: June 15, 2018; Value-Line 11/13/2017 $ 52.22 $ 50.13 $ 50.89 11/20/2017 $ 51.05 $ 50.35 $ 50.71 11/27/2017 $ 51.84 $ 50.61 $ 51.36 NASDAQ : XEL Mean 12/4/2017 $ 51.58 $ 50.40 $ 51.20 LT Growth(%) 5.67 5.60 6.30 5.00 0.40 7 12/11/2017 $ 51.45 $ 50.16 $ 50.78 Source: SNL/S&P Global 12/18/2017 $ 50.86 $ 48.12 $ 48.25 12/25/2017 $ 48.41 $ 47.53 $ 48.11 5.90 5.00 1/1/2018 $ 48.36 $ 46.63 $ 46.79 1/8/2018 $ 47.22 $ 45.06 $ 45.15 1/15/2018 $ 45.86 $ 44.89 $ 45,13 5.80 5.80 1/22/2018 $ 46.10 $ 45.12 $ 45.70 1/29/2018 $ 45.78 $ 44.45 $ 44.48 2/5/2018 $ 44.75 $ 41.51 $ 43.35 2/12/2018 $ 44.88 $ 43.04 $ 44.68 5.70 5.70 2/19/2018 2/26/2018 | 10/16/2017 $ 49.41 $ 48.26 $ 49.26 10/23/2017 $ 49.83 $ 48.56 $ 49.21 2017 2018 .2019 '21 to '23 10/30/2017 $ 49.92 $ 48.93 $ 49.59 $ 1.44 $ 1.52 $ 1.60 $ 1.90 11/6/2017 $ 50.57 $ 49.29 $ 50.20 Source: June 15, 2018; Value-Line 11/13/2017 $ 52.22 $ 50.13 $ 50.89 11/20/2017 $ 51.05 $ 50.35 $ 50.71 11/27/2017 $ 51.84 $ 50.61 $ 51.36 NASDAQ : XEL Mean 12/4/2017 $ 51.58 $ 50.40 $ 51.20 LT Growth(%) 5.67 5.60 6.30 5.00 0.40 7 12/11/2017 $ 51.45 $ 50.16 $ 50.78 Source: SNL/S&P Global 12/18/2017 $ 50.86 $ 48.12 $ 48.25 12/25/2017 $ 48.41 $ 47.53 $ 48.11 5.90 5.00 1/1/2018 $ 48.36 $ 46.63 $ 46.79 1/8/2018 $ 47.22 $ 45.06 $ 45.15 1/15/2018 $ 45.86 $ 44.89 $ 45,13 5.80 5.80 1/22/2018 $ 46.10 $ 45.12 $ 45.70 1/29/2018 $ 45.78 $ 44.45 $ 44.48 2/5/2018 $ 44.75 $ 41.51 $ 43.35 2/12/2018 $ 44.88 $ 43.04 $ 44.68 5.70 5.70 2/19/2018 2/26/2018 44.82 44.92 43.50 $ 44.77 42.65 $ 43.03 | ||
44.82 44.92 | |||
43.50 $ 44.77 42.65 $ 43.03 | |||
] | ] | ||
3/5/2018 $ 44.02 $ 42.57 $ 43.28 5.50 5.60 3/12/2018 $ 44 .23 $ 43.23 $ 44.13 3/19/2018 $ 45.19 $ 43.66 $ 43.74 3/26/2018 $ 45.87 $ 43.81 $ 45.48 5.50 5.50 4/2/2018 $ 45.99 $ 44.68 $ 45.47 4/9/2018 $ 45.80 $ 43.93 $ 44.48 4/16/2018 $ 46.01 $ 44.49 $ 45.10 4/23/2018 $ 47.38 $ 45.12 $ 47.10 o.40 ' - - - , - | 3/5/2018 $ 44.02 $ 42.57 $ 43.28 5.50 5.60 3/12/2018 $ 44 .23 $ 43.23 $ 44.13 3/19/2018 $ 45.19 $ 43.66 $ 43.74 3/26/2018 $ 45.87 $ 43.81 $ 45.48 5.50 5.50 4/2/2018 $ 45.99 $ 44.68 $ 45.47 4/9/2018 $ 45.80 $ 43.93 $ 44.48 4/16/2018 $ 46.01 $ 44.49 $ 45.10 4/23/2018 $ 47.38 $ 45.12 $ 47.10 o.40 ' - - - , - | ||
* 4/30/2018 5/7/2018 5/14/2018 | * 4/30/2018 5/7/2018 5/14/2018 47.37 46.54 45.41 45.93 $ 46.39 44.58 $ 45.26 . | ||
47.37 46.54 45.41 | |||
45.93 $ 46.39 44.58 $ 45.26 . | |||
43.44 $ 43.70 | 43.44 $ 43.70 | ||
~ ~ ~ ~ | ~ ~ ~ ~ | ||
| Line 2,949: | Line 2,686: | ||
* This will be done in individual company dockets, separate from the instant docket. | * This will be done in individual company dockets, separate from the instant docket. | ||
: 6. Westar, KCP&L and KBPCo 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 yeat that the decommissioning*costs will occur. | : 6. Westar, KCP&L and KBPCo 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 yeat that the decommissioning*costs will occur. | ||
: 7. 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- | : 7. 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; however, just as the review process is currently split into two phases - a joint phase for the decommissioning cost study and the escalation factor, and a utility-specific phase for the individual utility financing plans - the utilities may determine to ~le certain of the requirements separately at the time of the joint filing _so long as all 11 requirements are covered. | ||
128m(b) by September 1, 2017; however, just as the review process is currently split into two phases - a joint phase for the decommissioning cost study and the escalation factor, and a utility-specific phase for the individual utility financing plans - the utilities may determine to ~le certain of the requirements separately at the time of the joint filing _so long as all 11 requirements are covered. | |||
: 8. 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. CURB, while not .a See Direct Testimony of Leo M. Haynos, filed Jan. 5, 2015, p. 12, lines 8-23. | : 8. 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. CURB, while not .a See Direct Testimony of Leo M. Haynos, filed Jan. 5, 2015, p. 12, lines 8-23. | ||
2 | 2 | ||
| Line 2,967: | Line 2,702: | ||
II. RESERVATIONS | II. RESERVATIONS | ||
: 10. Except as specified in, this S&A, none of the Parties to the agreement shall be | : 10. Except as specified in, this S&A, none of the Parties to the agreement shall be | ||
. deemed to have approved or acquiesced in any. question of the Commission authority, 3 | . deemed to have approved or acquiesced in any. question of the Commission authority, 3 | ||
| Line 2,988: | Line 2,722: | ||
(34 pages) | (34 pages) | ||
20181213103959 Kansas Corporation Commission | 20181213103959 Kansas Corporation Commission THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS Before Commissioners: Shari Feist Albrecht, Chair Jay Scott Emler Dwight D. Keen In the Matter of the Application of Kansas ) | ||
THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS Before Commissioners: Shari Feist Albrecht, Chair Jay Scott Emler Dwight D. Keen In the Matter of the Application of Kansas ) | |||
City Pow~r & Light Company to Make ) Docket No. 18-KCPE-480-RTS Certain Changes in its Charges for Electric ) | City Pow~r & Light Company to Make ) Docket No. 18-KCPE-480-RTS Certain Changes in its Charges for Electric ) | ||
Service. ) | Service. ) | ||
| Line 2,996: | Line 2,728: | ||
: l. On May l, 2018, Kansas City Power & Light Company (KCP&L) filed for a $32.9 million revenue increase, including property tax rebasing. 1 As a result of the Commission's approval of the merger of KCP&L's parent company, Great Plains Energy, Inc. 'with Westar Energy, Inc., on May 24, 2018 (the merger), KCP&L reduced its requested revenue increase to | : l. On May l, 2018, Kansas City Power & Light Company (KCP&L) filed for a $32.9 million revenue increase, including property tax rebasing. 1 As a result of the Commission's approval of the merger of KCP&L's parent company, Great Plains Energy, Inc. 'with Westar Energy, Inc., on May 24, 2018 (the merger), KCP&L reduced its requested revenue increase to | ||
$22.6 million.2 This Application was accompanied by the direct testimony from 14 witnesses. | $22.6 million.2 This Application was accompanied by the direct testimony from 14 witnesses. | ||
: 2. On June 26, 2018, Darrin Ives, Vice President - Regulatory Affairs for KCP&L, filed supplemental direct testimony to reflect the Commission's approval of the merger and | : 2. On June 26, 2018, Darrin Ives, Vice President - Regulatory Affairs for KCP&L, filed supplemental direct testimony to reflect the Commission's approval of the merger and reduced. KCP&L's requested revenue requirement, including property tax rebasing, from | ||
reduced. KCP&L's requested revenue requirement, including property tax rebasing, from | |||
$32,948,941 to $22,673,415. 3 | $32,948,941 to $22,673,415. 3 | ||
: 3. The Commission has jurisdiction to supervise and control electric public utilities, as defined in K.S.A. 66-IOla, doing business in Kansas. 4 The Commission has the power to 1 Application, May I, 2018, ,r 3. | : 3. The Commission has jurisdiction to supervise and control electric public utilities, as defined in K.S.A. 66-IOla, doing business in Kansas. 4 The Commission has the power to 1 Application, May I, 2018, ,r 3. | ||
| Line 3,016: | Line 2,746: | ||
2 | 2 | ||
: 7. Also, on September 12, 2018, Paul Raab filed direct testimony on behalf of Kansas Gas Service; Steve Chriss filed direct testimony oll behalf of Walmart; Andrea C. Crane, Brian Kalcic, and Stacey Harden filed testimony on behalf of CURB; and Tim Stringer, Justin Grady, William Baldry, Adam Gatewood, Roxie McCullar, Justin . | : 7. Also, on September 12, 2018, Paul Raab filed direct testimony on behalf of Kansas Gas Service; Steve Chriss filed direct testimony oll behalf of Walmart; Andrea C. Crane, Brian Kalcic, and Stacey Harden filed testimony on behalf of CURB; and Tim Stringer, Justin Grady, William Baldry, Adam Gatewood, Roxie McCullar, Justin . | ||
Prentiss, | Prentiss, Darren Prince,. Brad Hutton, | ||
Darren Prince,. Brad Hutton, | |||
*Joshua Frantz, Chad Unrein, Andria Jackson, and Dr. Robert Glass filed direct testimony on behalf of .Commission Staff (Staff). | *Joshua Frantz, Chad Unrein, Andria Jackson, and Dr. Robert Glass filed direct testimony on behalf of .Commission Staff (Staff). | ||
: 8. On September 19,2018, Raab, Kalcic, and Chriss filed cross-answering testimony. | : 8. On September 19,2018, Raab, Kalcic, and Chriss filed cross-answering testimony. | ||
| Line 3,060: | Line 2,787: | ||
5 | 5 | ||
: 17. The Unanimou~ Settlement Agreement is a "Unanimous settlement agreement" as defined by K.A.R. 82-l-230a. Therefore, there is no need to apply the five-factor test. 21 | : 17. The Unanimou~ Settlement Agreement is a "Unanimous settlement agreement" as defined by K.A.R. 82-l-230a. Therefore, there is no need to apply the five-factor test. 21 | ||
: 18. Substantial competent evidence possesses something of substance. and relevant consequence, which furnishes a substantial basis of fact to reasonably resolve the issues. 22 Whether another trier of fact could have reached a different conclusion given the same facts is irrelevant; a court can only find that a Commissio.n decision is not supported by substantial competent evidence when the evidence shows "the [Commission's] determination is so wide of the mark asto be outside | : 18. Substantial competent evidence possesses something of substance. and relevant consequence, which furnishes a substantial basis of fact to reasonably resolve the issues. 22 Whether another trier of fact could have reached a different conclusion given the same facts is irrelevant; a court can only find that a Commissio.n decision is not supported by substantial competent evidence when the evidence shows "the [Commission's] determination is so wide of the mark asto be outside the realm of fair debate."23 The Commission has reviewed the record in this Docket that consists of pre-filed testimony from a total of 34 witnesses, including 15 on behalf of KCP&L, live testimony of 4. witnesses, and the Joint Motion for Approval of Unanimous Settlement Agreement, supported by testimony from Aridrea Crane (CURB), Darrin Ives (KCP&L), David Banks (the Schools), and Justin Grady and Dr. Robert Glass (Staff). | ||
the realm of fair debate."23 The Commission has reviewed the record in this Docket that consists of pre-filed testimony from a total of 34 witnesses, including 15 on behalf of KCP&L, live testimony of 4. witnesses, and the Joint Motion for Approval of Unanimous Settlement Agreement, supported by testimony from Aridrea Crane (CURB), Darrin Ives (KCP&L), David Banks (the Schools), and Justin Grady and Dr. Robert Glass (Staff). | |||
: 19. Having reviewed the record as a whole, the Commission finds and concludes that | : 19. Having reviewed the record as a whole, the Commission finds and concludes that | ||
\ | \ | ||
| Line 3,075: | Line 2,800: | ||
Unanimous Settlement Agreement fairly represents a balance of the interests of the Signatories, reaches a reasonable result that is supported by the evidence, and is in the public interest. | Unanimous Settlement Agreement fairly represents a balance of the interests of the Signatories, reaches a reasonable result that is supported by the evidence, and is in the public interest. | ||
: 20. The requirement of just and reasonable rates incorporates the "zone of reasonableness" test, and is used to determine whether the rate is within an elusive range of reasonableness in calculating a fair rate of retum. 27 The Commission acts within its discretion in 28 finding an "in-between point, where the rate is most fair to the utility and its customers." The Commission considered the competing interests it must take into account in setting rates, and finds the agreed upon revenue requirement under the Unanimous Settlement Agreement falls within the "zone of reasonableness." There is substantial evidence in the record that the agreed-upon rates will provide KCP&L with sufficient revenues and cash flows to meet its financial obligations, yet will keep rates as low as possible while maintaining reliable service for its customers. Accordingly, the Commission finds and concludes that the approval of the Unanimous Settlement Agreement will result in just and reasonable rates for KCP&L and its customers. | : 20. The requirement of just and reasonable rates incorporates the "zone of reasonableness" test, and is used to determine whether the rate is within an elusive range of reasonableness in calculating a fair rate of retum. 27 The Commission acts within its discretion in 28 finding an "in-between point, where the rate is most fair to the utility and its customers." The Commission considered the competing interests it must take into account in setting rates, and finds the agreed upon revenue requirement under the Unanimous Settlement Agreement falls within the "zone of reasonableness." There is substantial evidence in the record that the agreed-upon rates will provide KCP&L with sufficient revenues and cash flows to meet its financial obligations, yet will keep rates as low as possible while maintaining reliable service for its customers. Accordingly, the Commission finds and concludes that the approval of the Unanimous Settlement Agreement will result in just and reasonable rates for KCP&L and its customers. | ||
: 21. The Commission finds that approval of the Unanimous Settlement Agreement is in the public interest. The Signatories agree the terms of the Unanimous Settlement Agreement are in the public interest and should be approved by the Commission.29 The Signatories explain that the terms of the Unanimous Settlement Agreement represent an equitable balancing of the interests of | : 21. The Commission finds that approval of the Unanimous Settlement Agreement is in the public interest. The Signatories agree the terms of the Unanimous Settlement Agreement are in the public interest and should be approved by the Commission.29 The Signatories explain that the terms of the Unanimous Settlement Agreement represent an equitable balancing of the interests of | ||
° all Signatories.3 Furthermore, the public interest is served by minimizing the cost of litigation, and passing those cost savings on to ratepayers. 31 27 Kansas Gas, 239 Kan. at 490. | ° all Signatories.3 Furthermore, the public interest is served by minimizing the cost of litigation, and passing those cost savings on to ratepayers. 31 27 Kansas Gas, 239 Kan. at 490. | ||
| Line 3,103: | Line 2,827: | ||
BY THE COMMISSION IT IS SO ORDERED. | BY THE COMMISSION IT IS SO ORDERED. | ||
Albrecht, Chair; Emler, Commissioner; Keen, Commissioner 12/l?/2018 Dated: | Albrecht, Chair; Emler, Commissioner; Keen, Commissioner 12/l?/2018 Dated: | ||
LynnM. Retz Secretary to the Commission BGF 32 K.S.A. 66-l 18b; K.S.A. 77-503(c); K.S.A. 77-53 l(b). | LynnM. Retz Secretary to the Commission BGF 32 K.S.A. 66-l 18b; K.S.A. 77-503(c); K.S.A. 77-53 l(b). | ||
9 | 9 | ||
| Line 3,167: | Line 2,890: | ||
(3) Depreciation | (3) Depreciation | ||
: 12. For settlement purposes only, Staffs depreciation rates will be adopted . | : 12. For settlement purposes only, Staffs depreciation rates will be adopted . | ||
Additionally, KCP&L will create a regulatory liability to capture the Kansas jurisdictional amount of depreciation expense included in KCP&L's revenue requirement beginning when the Montrose units are retired and depreciation expense is no longer recorded to the income statement associated with the Montrose units. The depreciation amounts ~ill accumulate in the regulatory liability account until new customer rates are established in the next KCP&L general rate case filed after this 2018 general rate case is completed. At that time, the regulatory liability account will be closed into accumulated depreciation. Additionally, the closing of this regulatory liability into accumulated depreciation will be reflected in rates that are established in that rate case. | Additionally, KCP&L will create a regulatory liability to capture the Kansas jurisdictional amount of depreciation expense included in KCP&L's revenue requirement beginning when the Montrose units are retired and depreciation expense is no longer recorded to the income statement associated with the Montrose units. The depreciation amounts ~ill accumulate in the regulatory liability account until new customer rates are established in the next KCP&L general rate case filed after this 2018 general rate case is completed. At that time, the regulatory liability account will be closed into accumulated depreciation. Additionally, the closing of this regulatory liability into accumulated depreciation will be reflected in rates that are established in that rate case. | ||
(4) Revenue Adjustments | (4) Revenue Adjustments | ||
| Line 3,199: | Line 2,921: | ||
(]) Revenue Allocation | (]) Revenue Allocation | ||
: 23. The Signatories agree to the following revenue decrease allocation among the customer classes: | : 23. The Signatories agree to the following revenue decrease allocation among the customer classes: | ||
Proposed Proposed Revenue from Existing KANSAS RATE GROUP Decrease Decrease Rates | Proposed Proposed Revenue from Existing KANSAS RATE GROUP Decrease Decrease Rates LARGE GEN SVC TOTAL * $162,402;701 . $(1,625,875) -1.001% | ||
LARGE GEN SVC TOTAL * $162,402;701 . $(1,625,875) -1.001% | |||
MEDIUM GEN SVC TOTAL $69,285,911 $(693,648) -1.001% | MEDIUM GEN SVC TOTAL $69,285,911 $(693,648) -1.001% | ||
SMALL GEN SVC TOTAL $43,958,196 $(527,498) -1.200% | SMALL GEN SVC TOTAL $43,958,196 $(527,498) -1.200% | ||
| Line 3,242: | Line 2,962: | ||
ATTACHMENT A New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. | ATTACHMENT A New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. | ||
: b. The Company will report annually to Staff and CURB the following information for the Residential Distributed Generation rate: | : b. The Company will report annually to Staff and CURB the following information for the Residential Distributed Generation rate: | ||
(i) number of residential DG customers taking service from the rate, (ii) the total demand and energy charges paid during the year, (iii) annual energy consumption data by customer, and (iv) annual total bill amounts (less riders) by customer. | (i) number of residential DG customers taking service from the rate, (ii) the total demand and energy charges paid during the year, (iii) annual energy consumption data by customer, and (iv) annual total bill amounts (less riders) by customer. | ||
| Line 3,263: | Line 2,982: | ||
: a. KCP&L shall be authorized to pursue a build option or Power Purchase Agreement ("PPA") for solar resources. | : a. KCP&L shall be authorized to pursue a build option or Power Purchase Agreement ("PPA") for solar resources. | ||
: b. KCP&L's selection of either a build option or PPA for solar resources will be based on least cost to customers. | : b. KCP&L's selection of either a build option or PPA for solar resources will be based on least cost to customers. | ||
: c. The revenue requirement for inclusion in rates for a Company-owned solar built project will be levelized over the life of the project if the cost of the | : c. The revenue requirement for inclusion in rates for a Company-owned solar built project will be levelized over the life of the project if the cost of the solar resource exceeds $10 million. For projects under this amount, parties reserve their ability to address the methodology for inclusion in KCP&L's revenue requirement at the time the solar resource is included in a future general rate proceeding. | ||
solar resource exceeds $10 million. For projects under this amount, parties reserve their ability to address the methodology for inclusion in KCP&L's revenue requirement at the time the solar resource is included in a future general rate proceeding. | |||
: d. KCP&L will not build or enter into a PPA for a solar project until the project ,is 75% subscribed, and the cost of any unsubscribed portion will 12 | : d. KCP&L will not build or enter into a PPA for a solar project until the project ,is 75% subscribed, and the cost of any unsubscribed portion will 12 | ||
| Line 3,322: | Line 3,039: | ||
* Interdependent Provisions | * Interdependent Provisions | ||
: 41. The provisions of this Settlement have resulted from negotiations among the Signatory Parties and are interdependent. In the event that the Commission does not approve and adopt the terms of this Settlement in total or materially changes the Settlement terms, | : 41. The provisions of this Settlement have resulted from negotiations among the Signatory Parties and are interdependent. In the event that the Commission does not approve and adopt the terms of this Settlement in total or materially changes the Settlement terms, | ||
* the Settlement shall be voidable and no Signatory Party hereto shall be bound, prejudiced, or in any way affected by .any of the agreements or provisions hereof. Further, in the event the Commission does not approve and adopt the terms of this Settlement in total, this Settlement shall be considered privileged and not admissible in evidence or made a part of the record in any proceeding. In the event of a termination pursuant to this Section, the Settlement shall be null and void and of no further effect, with all rights, duties, and obligations of the Signatory Parties | * the Settlement shall be voidable and no Signatory Party hereto shall be bound, prejudiced, or in any way affected by .any of the agreements or provisions hereof. Further, in the event the Commission does not approve and adopt the terms of this Settlement in total, this Settlement shall be considered privileged and not admissible in evidence or made a part of the record in any proceeding. In the event of a termination pursuant to this Section, the Settlement shall be null and void and of no further effect, with all rights, duties, and obligations of the Signatory Parties thereafter restored as if this Settlement had never been executed; provided, that the Signatory Parties may, in the sole discretion of each Party, agree to attempt to modify the Settlement in a | ||
thereafter restored as if this Settlement had never been executed; provided, that the Signatory Parties may, in the sole discretion of each Party, agree to attempt to modify the Settlement in a | |||
*manner that would resolve the adver~e effect of the material change of condition. | *manner that would resolve the adver~e effect of the material change of condition. | ||
18 | 18 | ||
| Line 3,352: | Line 3,067: | ||
Attachment A Page 1 of 1 | Attachment A Page 1 of 1 | ||
CERTIFICATE OF SERVICE | CERTIFICATE OF SERVICE 18-KCPE-480-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 _ _ 12_1_ | ||
18-KCPE-480-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 _ _ 12_1_ | |||
1_31_2_0_18_ _ _ __ | 1_31_2_0_18_ _ _ __ | ||
JAMES G. FLAHERTY, ATTORNEY MARTIN J. BREGMAN ANDERSON & BYRD, L.L.P. BREGMAN LAW OFFICE, L.L.C. | JAMES G. FLAHERTY, ATTORNEY MARTIN J. BREGMAN ANDERSON & BYRD, L.L.P. BREGMAN LAW OFFICE, L.L.C. | ||
| Line 3,412: | Line 3,125: | ||
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 Staffs range. | 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 Staffs range. | ||
Range of Staff Proposed Rate of Return Assuming Staffs Proposed Capital Structure Return on Equityi 9. 00% 9.25%i 9.50% | Range of Staff Proposed Rate of Return Assuming Staffs Proposed Capital Structure Return on Equityi 9. 00% 9.25%i 9.50% | ||
Rate ofReturn' 7.46% 7.59%1 7.72%; | Rate ofReturn' 7.46% 7.59%1 7.72%; | ||
3 4 Q Please summarize why you believe 9.25% is a reasonable ROE. | 3 4 Q Please summarize why you believe 9.25% is a reasonable ROE. | ||
| Line 3,444: | Line 3,156: | ||
Average; 4.s8: | Average; 4.s8: | ||
Source: Moody's !' | Source: Moody's !' | ||
1 Yield on Baa Utility Bonds 10.00 9.00 8.00 7.00 6.00 4.00 2.00 1.00 | 1 Yield on Baa Utility Bonds 10.00 9.00 8.00 7.00 6.00 4.00 2.00 1.00 0.00 .,., .,., | ||
0.00 .,., .,., | |||
,-. <- en en | ,-. <- en en | ||
'D | 'D | ||
| Line 3,453: | Line 3,163: | ||
9§ 0 9 ~ 0 0 | 9§ 0 9 ~ 0 0 | ||
" ~ ~ § § § § | " ~ ~ § § § § | ||
::i | ::i | ||
....." .....§ .=; 3 | ....." .....§ .=; 3 | ||
| Line 3,504: | Line 3,212: | ||
i i Summary ofWestar's Cost of Equity Estimates | i i Summary ofWestar's Cost of Equity Estimates | ||
& Growth Rates i | & Growth Rates i | ||
Range of | Range of | ||
! Methodology Output Discussion | ! Methodology Output Discussion | ||
| Line 3,520: | Line 3,227: | ||
. . .! commissions and the prevailing1 interest | . . .! commissions and the prevailing1 interest | ||
................................. rates. ' | ................................. rates. ' | ||
8 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? | 8 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 suppo1i its contention that a Commission's 18 decision has impaired its ability to access necessary capital. However, what I 11 | 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 suppo1i its contention that a Commission's 18 decision has impaired its ability to access necessary capital. However, what I 11 | ||
| Line 3,530: | Line 3,236: | ||
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. | 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. | ||
C?mponents of an Allowed Rate of Return Weighted i ! . | C?mponents of an Allowed Rate of Return Weighted i ! . | ||
Debt A : Ratlo of Debt Weighted A\erage Capital: \erage ! x Ca ital Cost of Debt Interest Rate p Allowed Equity :Ratio ofEquity WeightedA,erage Return on Capital: 'x ! Capital . = : Cost of Equity Equity I I | Debt A : Ratlo of Debt Weighted A\erage Capital: \erage ! x Ca ital Cost of Debt Interest Rate p Allowed Equity :Ratio ofEquity WeightedA,erage Return on Capital: 'x ! Capital . = : Cost of Equity Equity I I Sum Equals Allowed Rate of Return for the Utility 16 17 The cost of debt generally relies on a contractual agreement with the investor, 12 | ||
Sum Equals Allowed Rate of Return for the Utility 16 17 The cost of debt generally relies on a contractual agreement with the investor, 12 | |||
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 making its cost relatively easy to detennine 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 cam1ot 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. | Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 making its cost relatively easy to detennine 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 cam1ot 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. | ||
| Line 3,583: | Line 3,287: | ||
*Long-term Rating Baal ;BBB+ | *Long-term Rating Baal ;BBB+ | ||
Outlook Stable ;_Stabl_e | Outlook Stable ;_Stabl_e | ||
!Westar Energy | !Westar Energy | ||
/Long-term Rating Baal [BBB+ BBB | /Long-term Rating Baal [BBB+ BBB | ||
| Line 3,596: | Line 3,299: | ||
AAA l Aaa M+ Aal M Aa2 M- Aa3 A+ Al A A2 Proxy A- A3 i Selection BBB+ Baal :Westar Long-term Rating I | AAA l Aaa M+ Aal M Aa2 M- Aa3 A+ Al A A2 Proxy A- A3 i Selection BBB+ Baal :Westar Long-term Rating I | ||
Range BBB Baa2 i i | Range BBB Baa2 i i | ||
BBB- Baa3 I i | BBB- Baa3 I i BB+ Bal lI BB Ba2 BB- Ba3 i B+ Bl B B2 B- B3 j CCC+ Caal CCC Caa2 CCC- Caa3 cc Ca C | ||
BB+ Bal lI BB Ba2 | |||
BB- Ba3 i B+ Bl B B2 B- B3 j CCC+ Caal CCC Caa2 CCC- Caa3 cc Ca C | |||
D D 1 | D D 1 | ||
2 The electric utilities followed by Value-Line fall in the range of AA-/Aa3 3 to BBB-/Baa3. Nanowing the range to one rating above and below that of 4 Westar's rating reduced the proxy group to 35 companies. | 2 The electric utilities followed by Value-Line fall in the range of AA-/Aa3 3 to BBB-/Baa3. Nanowing the range to one rating above and below that of 4 Westar's rating reduced the proxy group to 35 companies. | ||
| Line 3,634: | Line 3,333: | ||
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: | 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: | ||
.) | .) | ||
* Investors evaluate common stock in the classical economic framework. | * Investors evaluate common stock in the classical economic framework. | ||
| Line 3,712: | Line 3,410: | ||
32 | 32 | ||
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS | Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS Cash Flow Westar 15-WSEE-115-RTS | ||
Cash Flow Westar 15-WSEE-115-RTS | |||
' Stall's | ' Stall's | ||
'l - Discounted | 'l - Discounted | ||
| Line 3,739: | Line 3,435: | ||
Average oflow&High 6.41%: | Average oflow&High 6.41%: | ||
M,.?'Yo 10.88%1 1*K~C proxy gr_oup Pricing March | M,.?'Yo 10.88%1 1*K~C proxy gr_oup Pricing March | ||
- .May; | - .May; | ||
- I 2: 2016 fore casted dividend/ observed high stock price I 3: 2016 forecastcd divid~nd / ob;~rv~d l~w sto~k price 4 *gro\Vth.rate, _ave~age of long-run and shorJ:run foreca;;t~d grm,th 5 *Min Dividen_d Yield+ Gro,,1h Rate 6: Max Dividend Yield+ Grav.th Rate N_o observatios \\ere climillat~d as i]logical or outliers. The test for low outliers is yield on Baa utHity bonds | - I 2: 2016 fore casted dividend/ observed high stock price I 3: 2016 forecastcd divid~nd / ob;~rv~d l~w sto~k price 4 *gro\Vth.rate, _ave~age of long-run and shorJ:run foreca;;t~d grm,th 5 *Min Dividen_d Yield+ Gro,,1h Rate 6: Max Dividend Yield+ Grav.th Rate N_o observatios \\ere climillat~d as i]logical or outliers. The test for low outliers is yield on Baa utHity bonds | ||
| Line 3,911: | Line 3,606: | ||
.. . Returns | .. . Returns | ||
. &. Treasury | . &. Treasury | ||
. !Bond Yields | . !Bond Yields Proxy Group & Westar Beta I)\ForecastedReturns on Common Stocks 7.60%\ | ||
Proxy Group & Westar Beta I)\ForecastedReturns on Common Stocks 7.60%\ | |||
2)/Forecasted Total Return on 10 Year T-Bonds 4.41%[ | 2)/Forecasted Total Return on 10 Year T-Bonds 4.41%[ | ||
i | i | ||
| Line 3,919: | Line 3,612: | ||
: 4) iBeta Coefficient l -- - | : 4) iBeta Coefficient l -- - | ||
xi 0.75 i 5): Risk.Premium 2.39%1 6)!Forecasted Yield on lQYear T-Bonds +: 4.25%1 | xi 0.75 i 5): Risk.Premium 2.39%1 6)!Forecasted Yield on lQYear T-Bonds +: 4.25%1 | ||
: 7) Forecasted Cost of Equity 6.64%: | |||
: 7) Forecasted Cost of Equity | |||
6.64%: | |||
: 1) !Forecasted 10 to 15 Year Annual Return Arithmetic return on stocks for large companies | : 1) !Forecasted 10 to 15 Year Annual Return Arithmetic return on stocks for large companies | ||
; ** ***-* *+ | ; ** ***-* *+ | ||
| Line 3,932: | Line 3,622: | ||
* 5)/row3 xrow4 = a%et specific risk premium 6)!Forec~t~d Yield on 10 y~ar U.s: T~easu~ Bonds Forecasted by lJ.P. Morgan Asset Management 2015 Edition; Fixed Income Assumptions; Exhibit 2; p.56 I | * 5)/row3 xrow4 = a%et specific risk premium 6)!Forec~t~d Yield on 10 y~ar U.s: T~easu~ Bonds Forecasted by lJ.P. Morgan Asset Management 2015 Edition; Fixed Income Assumptions; Exhibit 2; p.56 I | ||
: 7) Forecasted cost of equity capital row 5 + row 6 ! . | : 7) Forecasted cost of equity capital row 5 + row 6 ! . | ||
Sources:: | Sources:: | ||
J :p. Morgan Asset_Management, I AJng-term Capital Market Return Asstm1ptions 1 2015 Edition; J.P. Morgan A5set Management. | J :p. Morgan Asset_Management, I AJng-term Capital Market Return Asstm1ptions 1 2015 Edition; J.P. Morgan A5set Management. | ||
| Line 3,948: | Line 3,636: | ||
i Beta I I | i Beta I I | ||
: 1) !Total Returns on Common Stocks 12.10%1 | : 1) !Total Returns on Common Stocks 12.10%1 | ||
: 2) ITotal Return on Government Bonds 6.40%! | : 2) ITotal Return on Government Bonds 6.40%! | ||
, I | , I | ||
| Line 3,954: | Line 3,641: | ||
* 5.70%1 i | * 5.70%1 i | ||
4); Beta Coefficient Xj 0.75 i | 4); Beta Coefficient Xj 0.75 i | ||
: 5) Risk Premium 4}8%1 I | : 5) Risk Premium 4}8%1 I | ||
: 6) iYield on Government Bonds +i,, 5.12%! | : 6) iYield on Government Bonds +i,, 5.12%! | ||
| Line 4,118: | Line 3,804: | ||
/Total Rate Base (Application Section 3) *$ 5,062,804,912 i iEquity Ratio of Capital Structure 53%; | /Total Rate Base (Application Section 3) *$ 5,062,804,912 i iEquity Ratio of Capital Structure 53%; | ||
i' Equity Financed R:.c1te Base .$ 2,683,286,603 j l | i' Equity Financed R:.c1te Base .$ 2,683,286,603 j l | ||
iFlotation Cost 0.12%. | iFlotation Cost 0.12%. | ||
/Tax Gross Up Factor 0.6667 | /Tax Gross Up Factor 0.6667 | ||
| Line 4,259: | Line 3,944: | ||
~-22 | ~-22 | ||
"'>'22 7.29 6.86 6.06 5.93 Apr-27 M2y-27 Jun-27 5.49 5.50 '*"' | "'>'22 7.29 6.86 6.06 5.93 Apr-27 M2y-27 Jun-27 5.49 5.50 '*"' | ||
Apr-32 1Uy-32 9.56 10.21 6.SJ 7.36 Apr-37 | Apr-32 1Uy-32 9.56 10.21 6.SJ 7.36 Apr-37 | ||
}.{ay-37 4.98 5.02 4.07 4.00 Apr-42 | }.{ay-37 4.98 5.02 4.07 4.00 Apr-42 | ||
~Uy-42 3.79 3.76 3.09 3.10 Apr-47 M>)'-47 3.IJ.I 3.03 2.70 2.70 Apr-52 l\fay-52 3.54 3.54 3.23 3.22 Jun-22 6.92 5.91 5.51 5.05 Jun-32 10.70 7.57 fan.Ji 5.17 3.99 Joo-42 3.73 3.12 fon-47 3.04 2.71 Jun-52 3.55 3.22 Jul-22 6.83 5.&9 Jul-27 5.48 s.os Jul-32 10.11 7.28 Jul-37 :5.0S 3.94 Jul-42 3.68 3.10 Jul-47 3.03 273 Jul-52 3.53 3.22 Aus:-22 6.SS S.S6 Auc-27 5.43 5.02 Aug.-32 7.92 G.35 Aus-37 S.04 H9 Au.;-42 3.67 3.10 Aug-47 3.02 2.73 Aus-S2 3.50 3.24 Sep-22 6.77 5.69 Sep-27 5.41 4.9S Sep-,32 7.4S 5.91 Sep-37 5.25 3.96 Sep-42 3.66 3.08 Sep-47 3.06 2.SO Sep-52 3.50 3.24 Oet-22 6.51 5.S3 Oct-27 5.39 4.95 Oet-32 i.Si 5.SJ Oct-37 5.53 4.09 Oc:t-42 3.6:S 3.08 Oct-47 3.13 2.SS Oct-52 3.50 3.26 Xov-22 656 5.S7 Nov-27 5JS 4.92 Nov-32 S.32 5.SS );ov-37 5.59 4.08 1':ov-42 3.67 3.07 Nov-4i 3.IS 2.93 Nov--52 3.4i 3.24 De:-22 6.56 S.9S Dec:*27 S.32 4.SS Dec-31 S.41 5.SS ~-37 S.60 4.03 Dec-12 3.6S 3.06 Dec-47 3.25 3.05 Dec-S2 3.50 3.22 Jun-23 6.59 5.&5 J:m-2S S.24 4.S5 J:in-33 S.S6 5.39 Jm-38 5.59 4.01 J:m-13 3.65 J.OS Jan-48 3.30 3.05 fan-53 3.51 3.25 Feb-23 6.6-0 5.33 Feb-2S 5.20 4.85 Feb-33 7.58 5.11 Feb-3S 5.79 4.03 Feb-4-3 3.61 3.02 Fcb-48 3.3i 3.05 Feb-53 3.53 3.30 r-.far-23 6.73 6.06 M:u'*2S 5.JS 4.82 ?i.far-33 7.SS 6.34 ).hr-JS 5.80 3.99 Ma:r-43 3.5S 3.01 ).llt-4S 3.29 3.02 Mu-53 3.56 3.36 Apr-23 6.7S 6.04 Apr-2S :5.lS 4.S2 Ap:-33 7.1S 6.S9 Apr-JS 5.S2 4.0S Apr-43 l.60 3.00 Apr-4S 3.28 2.97 Apr-53 3.62 3.47 May-23 Jun-23 Jul-23 6.78 6.80 6.79 6.00 6.06 6.02 | ~Uy-42 3.79 3.76 3.09 3.10 Apr-47 M>)'-47 3.IJ.I 3.03 2.70 2.70 Apr-52 l\fay-52 3.54 3.54 3.23 3.22 Jun-22 6.92 5.91 5.51 5.05 Jun-32 10.70 7.57 fan.Ji 5.17 3.99 Joo-42 3.73 3.12 fon-47 3.04 2.71 Jun-52 3.55 3.22 Jul-22 6.83 5.&9 Jul-27 5.48 s.os Jul-32 10.11 7.28 Jul-37 :5.0S 3.94 Jul-42 3.68 3.10 Jul-47 3.03 273 Jul-52 3.53 3.22 Aus:-22 6.SS S.S6 Auc-27 5.43 5.02 Aug.-32 7.92 G.35 Aus-37 S.04 H9 Au.;-42 3.67 3.10 Aug-47 3.02 2.73 Aus-S2 3.50 3.24 Sep-22 6.77 5.69 Sep-27 5.41 4.9S Sep-,32 7.4S 5.91 Sep-37 5.25 3.96 Sep-42 3.66 3.08 Sep-47 3.06 2.SO Sep-52 3.50 3.24 Oet-22 6.51 5.S3 Oct-27 5.39 4.95 Oet-32 i.Si 5.SJ Oct-37 5.53 4.09 Oc:t-42 3.6:S 3.08 Oct-47 3.13 2.SS Oct-52 3.50 3.26 Xov-22 656 5.S7 Nov-27 5JS 4.92 Nov-32 S.32 5.SS );ov-37 5.59 4.08 1':ov-42 3.67 3.07 Nov-4i 3.IS 2.93 Nov--52 3.4i 3.24 De:-22 6.56 S.9S Dec:*27 S.32 4.SS Dec-31 S.41 5.SS ~-37 S.60 4.03 Dec-12 3.6S 3.06 Dec-47 3.25 3.05 Dec-S2 3.50 3.22 Jun-23 6.59 5.&5 J:m-2S S.24 4.S5 J:in-33 S.S6 5.39 Jm-38 5.59 4.01 J:m-13 3.65 J.OS Jan-48 3.30 3.05 fan-53 3.51 3.25 Feb-23 6.6-0 5.33 Feb-2S 5.20 4.85 Feb-33 7.58 5.11 Feb-3S 5.79 4.03 Feb-4-3 3.61 3.02 Fcb-48 3.3i 3.05 Feb-53 3.53 3.30 r-.far-23 6.73 6.06 M:u'*2S 5.JS 4.82 ?i.far-33 7.SS 6.34 ).hr-JS 5.80 3.99 Ma:r-43 3.5S 3.01 ).llt-4S 3.29 3.02 Mu-53 3.56 3.36 Apr-23 6.7S 6.04 Apr-2S :5.lS 4.S2 Ap:-33 7.1S 6.S9 Apr-JS 5.S2 4.0S Apr-43 l.60 3.00 Apr-4S 3.28 2.97 Apr-53 3.62 3.47 May-23 Jun-23 Jul-23 6.78 6.80 6.79 6.00 6.06 6.02 Jun-28 Jul-28 5.23 5.38 5.38 4.$7 4.99 S.04 May-33 Jun-33 Jul-33 7.17 7.20 i.36 6.$0 6.11 5.91 | ||
Jun-28 Jul-28 5.23 5.38 5.38 4.$7 4.99 S.04 May-33 Jun-33 Jul-33 7.17 7.20 i.36 6.$0 6.11 5.91 | |||
?..fay-3S Jun-JS Ju!-3S 5.32 5.33 5.01 3.95 3.95 3.S6 1fay-43 Jun-n Jul-43 3.60 3.60 3.55 3.00 2.98 2.96 M.ay-4S fon-4S fol-48 3.27 3.29 3.34 2.94 2.94 2.99 | ?..fay-3S Jun-JS Ju!-3S 5.32 5.33 5.01 3.95 3.95 3.S6 1fay-43 Jun-n Jul-43 3.60 3.60 3.55 3.00 2.98 2.96 M.ay-4S fon-4S fol-48 3.27 3.29 3.34 2.94 2.94 2.99 | ||
:-.tay-53 Jun-53 Ju!-53 3.76 3.SO 3.83 3.63 3.71 3.66 Aug-23 6.71 S.77 Au;;-2S 5.43 5.0S Aug:-33 7.6& 5.9S Aug-JS 4.93 3.S4 Aug-43 3.55 2.96 Aug-48 3.40 3.03 Aug-53 3.SS 3.61 Scp-23 6.Sl S.95 Sep-2S SAS 5.05 Sep-33 7.62 6.36 Sep-38 5.05 3.88 Sep-43 3.55 :.96 S,p--48 3.42 3.05 Sep-53 3.93 3.62 Oct-23 6.19 5.9S Oct-ZS 5.43 4.99 Oct-33 7.3S 6.36 Oct-JS 4.90 3.79 Oc:t-43 3.53 2.97 Oa-4S 3.44 3.03 Oct-53 3.S6 3.49 Nov-23 6.78 6.00 :-:ov-2S 5.3S 4.9S Nov-33 7.21 7.06 ~ov-38 4.71 3.73 Nov-43 3.55 2.9S Nov-4S 3.4S 3.07 Nov-53 3.7S 3.40 Dec-23 6.SO 6.05 Dce-2S 5.32 5.05 Dec-33 7.03 7.22 Dec-38 4.77 3.74 Dee-43 3.55 2.99 Doc-4S 3.47 3.06 Dei:-53 3.72 3.3S | :-.tay-53 Jun-53 Ju!-53 3.76 3.SO 3.83 3.63 3.71 3.66 Aug-23 6.71 S.77 Au;;-2S 5.43 5.0S Aug:-33 7.6& 5.9S Aug-JS 4.93 3.S4 Aug-43 3.55 2.96 Aug-48 3.40 3.03 Aug-53 3.SS 3.61 Scp-23 6.Sl S.95 Sep-2S SAS 5.05 Sep-33 7.62 6.36 Sep-38 5.05 3.88 Sep-43 3.55 :.96 S,p--48 3.42 3.05 Sep-53 3.93 3.62 Oct-23 6.19 5.9S Oct-ZS 5.43 4.99 Oct-33 7.3S 6.36 Oct-JS 4.90 3.79 Oc:t-43 3.53 2.97 Oa-4S 3.44 3.03 Oct-53 3.S6 3.49 Nov-23 6.78 6.00 :-:ov-2S 5.3S 4.9S Nov-33 7.21 7.06 ~ov-38 4.71 3.73 Nov-43 3.55 2.9S Nov-4S 3.4S 3.07 Nov-53 3.7S 3.40 Dec-23 6.SO 6.05 Dce-2S 5.32 5.05 Dec-33 7.03 7.22 Dec-38 4.77 3.74 Dee-43 3.55 2.99 Doc-4S 3.47 3.06 Dei:-53 3.72 3.3S | ||
| Line 4,284: | Line 3,966: | ||
)..iu-57 4.25 4.05 Milr-62 4.85 4.64 M:u-67 5.69 5.44 )..{:ir.72 8.26 7.77 :\fu-77 9.20 S.70 Mz-82 Ii.16 16.50 Mar-Si 9.19 S.93 Apr-57 4.14 4.01 Apr-62 4.SI 4.59 Apr-67 5.74 5.42 Aj<-72 S.30 7.S2 Apr-77 9.17 S.71 Apr-S2 17.00 16.31 ,\pr-S7 9.85 9.3S 1Uy-57 4.28 4.01 :-.Uy-62 4.74 4.51 :\fa.y-67 5.93 5.66 !.ily-71 8.30 7.S4 }.-by-77 9.13 5.7: May-S2 !6.6S 16.04 M;ty-S7 10.40 9.91 Jun-57 4.33 4.09 Jun-62 4.6& 4.4S Jun-67 6.14 l.S4 Jun-72 8.31 7.77 Jun-77 9.02 S.5S Jun-32 17.21 16.42 Jun-S7 10.46 10.02 Jul-57 4.41 4.20 Jul-62 4.6S 4.50 Ju!-67 6.23 5.94 Ju!-72 8.36 7.82 Jul-77 S.97 S.SI Jul-S2 17-09 16.42 Jul-S7 10.62 IO.IS Aug-Si 4.19 4.37 Aug-62 4.72 4.53 Aug-67 6.29 5.96 Aug-72 8.22 7.64 Au:;-77 S.91 S.49 Aug-82 16.37 15.83 Au:;-S7 10.90 10.45 Sep-Si 4.66 4.55 Scp-62 4.74 4.51 S<p-67 6.32 6.05 S.,,-72 8.01 7.61 Sq,-77 s.ss S.46 Se;,-82 15,58 15.40 Sep-S7 11.58 ll.22 Oct-57 4.73 4.61 Oct-62 4.71 4.49 Oct-67 6.42 6.IS Oct-7.? 7.94 7.66 Oct-77 9.01 S.61 Oct-S2 15.10 14.79 Oct-S7 ll.29 J0.75 Nov-57 4.S2 4.62 ~ov-62 4.65 4.45 Nov-67 6.63 6.4& Nov-72 7.86 7.60 Nov-77 9.05 S.64 Xov-32 14.Sl 14.46 N'ov-87 ll.1S lo.61 Dec-Si 4.Sl 4.36 Dee-62 4.66 4.44 Dee-67 6.9I 6.67 Dec-72 7.7S 7.4S Dec-77 9.0S S.64 Det:-S2 14.69 14.43 Dec-S7 11.09 1054 131'1-Si 4,65 J:n-6S S.92 l4.S6 fan-SS JO.SO Feb-58 MU-SS 4.60 4.23 4.15 3.93 3.% | )..iu-57 4.25 4.05 Milr-62 4.85 4.64 M:u-67 5.69 5.44 )..{:ir.72 8.26 7.77 :\fu-77 9.20 S.70 Mz-82 Ii.16 16.50 Mar-Si 9.19 S.93 Apr-57 4.14 4.01 Apr-62 4.SI 4.59 Apr-67 5.74 5.42 Aj<-72 S.30 7.S2 Apr-77 9.17 S.71 Apr-S2 17.00 16.31 ,\pr-S7 9.85 9.3S 1Uy-57 4.28 4.01 :-.Uy-62 4.74 4.51 :\fa.y-67 5.93 5.66 !.ily-71 8.30 7.S4 }.-by-77 9.13 5.7: May-S2 !6.6S 16.04 M;ty-S7 10.40 9.91 Jun-57 4.33 4.09 Jun-62 4.6& 4.4S Jun-67 6.14 l.S4 Jun-72 8.31 7.77 Jun-77 9.02 S.5S Jun-32 17.21 16.42 Jun-S7 10.46 10.02 Jul-57 4.41 4.20 Jul-62 4.6S 4.50 Ju!-67 6.23 5.94 Ju!-72 8.36 7.82 Jul-77 S.97 S.SI Jul-S2 17-09 16.42 Jul-S7 10.62 IO.IS Aug-Si 4.19 4.37 Aug-62 4.72 4.53 Aug-67 6.29 5.96 Aug-72 8.22 7.64 Au:;-77 S.91 S.49 Aug-82 16.37 15.83 Au:;-S7 10.90 10.45 Sep-Si 4.66 4.55 Scp-62 4.74 4.51 S<p-67 6.32 6.05 S.,,-72 8.01 7.61 Sq,-77 s.ss S.46 Se;,-82 15,58 15.40 Sep-S7 11.58 ll.22 Oct-57 4.73 4.61 Oct-62 4.71 4.49 Oct-67 6.42 6.IS Oct-7.? 7.94 7.66 Oct-77 9.01 S.61 Oct-S2 15.10 14.79 Oct-S7 ll.29 J0.75 Nov-57 4.S2 4.62 ~ov-62 4.65 4.45 Nov-67 6.63 6.4& Nov-72 7.86 7.60 Nov-77 9.05 S.64 Xov-32 14.Sl 14.46 N'ov-87 ll.1S lo.61 Dec-Si 4.Sl 4.36 Dee-62 4.66 4.44 Dee-67 6.9I 6.67 Dec-72 7.7S 7.4S Dec-77 9.0S S.64 Det:-S2 14.69 14.43 Dec-S7 11.09 1054 131'1-Si 4,65 J:n-6S S.92 l4.S6 fan-SS JO.SO Feb-58 MU-SS 4.60 4.23 4.15 3.93 3.% | ||
4.13 Jan-63 Fd>-63 Mu-63 4.65 4.66 4.39 4.37 4.37 Fcb-6& | 4.13 Jan-63 Fd>-63 Mu-63 4.65 4.66 4.39 4.37 4.37 Fcb-6& | ||
)..fat-6S 6.76 6.6S 6.75 | )..fat-6S 6.76 6.6S 6.75 6.37 6.41 J:m-73 Fro-73 Mar-73 7.77 7.SS 7.95 7.52 7.62 7.66 fan-78 Fcb-78 M::--7S 9.27 9.29 9.37 S.97 8.9S Jan-SJ Feb-SJ | ||
6.37 6.41 J:m-73 Fro-73 Mar-73 7.77 7.SS 7.95 7.52 7.62 7.66 fan-78 Fcb-78 M::--7S 9.27 9.29 9.37 S.97 8.9S Jan-SJ Feb-SJ | |||
~fat-S3 14.61 14.33 14.24 14.26 13.94 Feb-SS Mar-SS 10.23 10.43 9.96 9.70 9.$4 Apr-58 4.15 3.95 Apr-63 4.67 4.37 Apr-68 6.94 6.SS A;ir-73 7.% 7.63 Apr-7S 9.54 9.09 Apr-SJ 14.07 13.61 Apr-SS 11.0S 10.40 | ~fat-S3 14.61 14.33 14.24 14.26 13.94 Feb-SS Mar-SS 10.23 10.43 9.96 9.70 9.$4 Apr-58 4.15 3.95 Apr-63 4.67 4.37 Apr-68 6.94 6.SS A;ir-73 7.% 7.63 Apr-7S 9.54 9.09 Apr-SJ 14.07 13.61 Apr-SS 11.0S 10.40 | ||
~*-58 4.23 -tot May-63 4.67 4.37 May-6S 6.99 6.62 :\1ay-73 7.91 7,63 .1,.13y-7S 9.70 9.2'2 h-tay-SJ 14.05 13.SO May-SS U.2S 10.72 Jir.-SS 4.20 3.99 Ju.n-63 4.67 4.37 Jun-6S 7.01 6.62 Jun*73 7.94 7.71 Jun-7S 9.7S 9.40 Jun-83 14.16 13.64 Jun-SS 11.00 10.53 Jul-SS 4.19 4.04 Jul-63 4.67 4.39 Jul-68 6.9:? 6.53 Ju!-73 8.10 7.S2 Jul-7S 9.73 9.5[ Jul-S3 14.01 13.58 Ju1-SS 11.22 10.75 Aus;-5S 4.44 4.29 Al.lg-63 4.66 4.3S Au;-6S 9.72 6.27 Aus-73 S.47 8.04 Aus-73 9.53 9.32 Au:;-83 14.21 13.57 Aug-SS 11.39 l0.S9 Sep-5S 4.69 4.55 S<p-63 4,69 4.40 Sep-6S 6.67 6.27 Scp-73 8.61 3.04 Sep-7S 9.47 9.28 Sep--83 14.10 13.42 Sep..SS !0.92 10.41 Oct-SS 4.74 4.56 Oct-63 J..66 4.41 Oct-6S 6.74 6.40 Oct-73 S.44 8.02 Oct-ii 9.69 9.46 Oct-83 13.9.5 13.25 Oct-SS JO.JI 10.0! | ~*-58 4.23 -tot May-63 4.67 4.37 May-6S 6.99 6.62 :\1ay-73 7.91 7,63 .1,.13y-7S 9.70 9.2'2 h-tay-SJ 14.05 13.SO May-SS U.2S 10.72 Jir.-SS 4.20 3.99 Ju.n-63 4.67 4.37 Jun-6S 7.01 6.62 Jun*73 7.94 7.71 Jun-7S 9.7S 9.40 Jun-83 14.16 13.64 Jun-SS 11.00 10.53 Jul-SS 4.19 4.04 Jul-63 4.67 4.39 Jul-68 6.9:? 6.53 Ju!-73 8.10 7.S2 Jul-7S 9.73 9.5[ Jul-S3 14.01 13.58 Ju1-SS 11.22 10.75 Aus;-5S 4.44 4.29 Al.lg-63 4.66 4.3S Au;-6S 9.72 6.27 Aus-73 S.47 8.04 Aus-73 9.53 9.32 Au:;-83 14.21 13.57 Aug-SS 11.39 l0.S9 Sep-5S 4.69 4.55 S<p-63 4,69 4.40 Sep-6S 6.67 6.27 Scp-73 8.61 3.04 Sep-7S 9.47 9.28 Sep--83 14.10 13.42 Sep..SS !0.92 10.41 Oct-SS 4.74 4.56 Oct-63 J..66 4.41 Oct-6S 6.74 6.40 Oct-73 S.44 8.02 Oct-ii 9.69 9.46 Oct-83 13.9.5 13.25 Oct-SS JO.JI 10.0! | ||
| Line 4,385: | Line 4,065: | ||
: 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 I IV. Generic Docket ..................................................................................................................... 44 V. Findings and Conclusions ..................................................................... ~ ............................. 45 | : 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 I 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: | 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 | I. Introduction A. Procedural History and Entries of Appearance | ||
| Line 4,428: | Line 4,107: | ||
;_ | ;_ | ||
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 | 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.t!ie service of a public utility except by filing with the Commission. | : 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.t!ie service of a public utility except by filing with the Commission. | ||
| Line 4,460: | Line 4,138: | ||
: 3. 2. Michael P. | : 3. 2. Michael P. | ||
: 4. Gorman | : 4. Gorman | ||
: 1. Jeff Hoppe 1. Jeff Hoppe 1. JeffHoppe Federal Executive Agencies | : 1. Jeff Hoppe 1. Jeff Hoppe 1. JeffHoppe Federal Executive Agencies | ||
: 1. Steve Chriss | : 1. Steve Chriss | ||
| Line 4,470: | Line 4,147: | ||
: 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 s*econd 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. | : 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 s*econd 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 maile!s included in every Westar customer's bill. 19 | : 17. Westar customers and the general public received notification by way of multiple newspapers throughout the state, as well as maile!s included in every Westar customer's bill. 19 | ||
: 18. The Commission took comments from the public regarding Westar's Application | : 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. | ||
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 Consume~ Protection Division (PACP) caused to be filed in the record a report summarizing the public comments , | : 19. On August 13, 2015; the Commission's Public Affairs and Consume~ Protection Division (PACP) caused to be filed in the record a report summarizing the public comments , | ||
received. 20 18 Order Modifying Procedural Schedule, 2 (Apr. 14, 2015). | received. 20 18 Order Modifying Procedural Schedule, 2 (Apr. 14, 2015). | ||
| Line 4,485: | Line 4,160: | ||
Wichita public hearing. The overwhelming public response received in this docket indicated general opposition to Westar' s initial Application. | 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 | 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. | : 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 appe~rance for counsel were as follows: | : 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 appe~rance for counsel were as follows: | ||
| Line 4,506: | Line 4,180: | ||
Environmental Defense Fund 1. Robert Eye Kroger Co. 1. | Environmental Defense Fund 1. Robert Eye Kroger Co. 1. | ||
Brightergy, LLC 1. Andrew Zellers 10 | Brightergy, LLC 1. Andrew Zellers 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 | : 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 | : 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 | ||
| Line 4,527: | Line 4,199: | ||
: 29. All remaining parties who had previously filed direct, cross-answering, and rebuttal testimony in this proceeding, as described above, moved to have their respective witnesses' testimo~ies entered into the record. 39 No party objected to the admittance of the testimony into the record and the Commission admitted the same. 40 II. Stipulation and Agreement A. Agreement and Addendum | : 29. All remaining parties who had previously filed direct, cross-answering, and rebuttal testimony in this proceeding, as described above, moved to have their respective witnesses' testimo~ies entered into the record. 39 No party objected to the admittance of the testimony into the record and the Commission admitted the same. 40 II. 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- | : 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-J Mart Stores, Inc., Tallgrass Pony Express Pipeline, LLC., Cargill, Inc., and Tyson Foods, 33 Id at 57-65. | ||
J Mart Stores, Inc., Tallgrass Pony Express Pipeline, LLC., Cargill, Inc., and Tyson Foods, 33 Id at 57-65. | |||
34 Id at 65-66. | 34 Id at 65-66. | ||
35 Id. at 66. | 35 Id. at 66. | ||
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15 | 15 | ||
the ECRR previously noticed to the Commission, and roll them into base rates established in a proposed abbreviated rate case discussed below. 65 | 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 l, 2017, consistent with improvements proposed as part of the Electric Distribution Grid Resiliency (EDGR) program discussed in the Direct Testimony of | : 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 l, 2017, consistent with improvements proposed as part of the Electric Distribution Grid Resiliency (EDGR) program discussed in the Direct Testimony of | ||
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66 S&A at ,r 20; See Direct Testimony of Jeffrey W. Cummings on Behalf of Westar Energy, exhibit JC-!, as amended (Jun. IO, 2015). | 66 S&A at ,r 20; See Direct Testimony of Jeffrey W. Cummings on Behalf of Westar Energy, exhibit JC-!, as amended (Jun. IO, 2015). | ||
67 S&A at ,r 20. | 67 S&A at ,r 20. | ||
68 Id at ,r 21. | |||
69 Direct Testimony of Chad Luce on Behalf of Westar Energy, 13 (Mar. 2, 2015). | 69 Direct Testimony of Chad Luce on Behalf of Westar Energy, 13 (Mar. 2, 2015). | ||
70 S&A at ,r 22. | 70 S&A at ,r 22. | ||
| Line 4,633: | Line 4,302: | ||
.of return for settlement purposes only, and do not view such return on equity as precedential. 83 | .of return 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 resulti11:g from this docket, until the amount is reset in a Commission order: 85 . | : 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 resulti11:g 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 | : 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 0f the Internal Revenue Code of. 1986 as amended. 86 | ||
comply with the tax normalization requirements 0f the Internal Revenue Code of. 1986 as amended. 86 | |||
: 54. Amortization Periods:* The Joint Movants propose the following amortization periods: | : 54. Amortization Periods:* The Joint Movants propose the following amortization periods: | ||
: a. Westar's actual rate case expense - three years; | : a. Westar's actual rate case expense - three years; | ||
: b. Regulatory asset associated with SmartStar Lawrence - three years; i | : b. Regulatory asset associated with SmartStar Lawrence - three years; i | ||
: c. Regulatory asset associated with SCR Catalyst - fifty-four months; 82 at Id ,r 30. | : c. Regulatory asset associated with SCR Catalyst - fifty-four months; 82 at Id ,r 30. | ||
83 Id. at ,r 30. | 83 Id. at ,r 30. | ||
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88 Id at ,r 34. | 88 Id at ,r 34. | ||
89 Id at ,r 35. | 89 Id at ,r 35. | ||
90 S&A at ,r 35. | |||
20 | 20 | ||
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: 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 I | : 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 I | ||
Appendix B of the S&A. 94 * | 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 | : 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 ,r 35. | ||
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 ,r 35. | |||
92 Id at ,r 36. | 92 Id at ,r 36. | ||
93 Id at ,r 36. | 93 Id at ,r 36. | ||
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. . 25 | . . 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 | 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 credii and enable it to raise the money necessary for the proper discharge of its | ||
support its credii 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 opportuni!ies 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 | . 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 opportuni!ies 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 depreciatiC?n allowance is to be earned." 130 These standards taken together stand for the general idea that the return provided to a 123 Order Approving Nonunanimous 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 for Electric Service, Docket No. 12-WSEE-112-RTS (Apr. I&, 2012) [hereinafter 12-112 Docket]. | * 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 depreciatiC?n allowance is to be earned." 130 These standards taken together stand for the general idea that the return provided to a 123 Order Approving Nonunanimous 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 for Electric Service, Docket No. 12-WSEE-112-RTS (Apr. I&, 2012) [hereinafter 12-112 Docket]. | ||
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* 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 | * 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? | : 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 | : 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 Com.mission 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, Inc. v. Kansas City Power & light Co., 267 Kan. 760, 773 (1999). | ||
parties. The Com.mission 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, Inc. v. Kansas City Power & light Co., 267 Kan. 760, 773 (1999). | |||
132 Citizens' Viii. Ratepayer Bd. v. State Corp. Comm 'n ofState of Kansas, 28 Kan. App. 2d 313, 3 16 (2000). | 132 Citizens' Viii. Ratepayer Bd. v. State Corp. Comm 'n ofState of Kansas, 28 Kan. App. 2d 313, 3 16 (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). | 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). | ||
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investment tax* credits, amortization periods, . pension trackers, and abbreviated rate case procedures and issues. 151 | 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 | : 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 | ||
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 | * contained in the S&A are comparable with an outcome that could be expected if the case were to be fully litigated. 154 | ||
,/ | ,/ | ||
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31 | 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, Di:. 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 | : 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, Di:. 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 beh~lf of CURB, testified that the S&A is supported by substantiai compe~ent 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 th~t was adopted by CURB, and utilizing a 9.35% cost of equity, would increase CURB's net revenue requirement from $50.80 niiHion 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 | : 87. Ms. Crane, on beh~lf of CURB, testified that the S&A is supported by substantiai compe~ent 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 th~t was adopted by CURB, and utilizing a 9.35% cost of equity, would increase CURB's net revenue requirement from $50.80 niiHion 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 tl;ie 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* char~es 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) | ||
issues decreased tl;ie 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* char~es 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]. | [hereinafter Glass S&A Testimony]. | ||
157 Id. at 3. . | 157 Id. at 3. . | ||
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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 cons1.d er. 11s . | 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 cons1.d er. 11s . | ||
: 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 | : 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 | * 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. | ||
this Commission approved them. 179 The Commission concurs with Mr. Greenwood's summation and rationale. | |||
9~. 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. | 9~. 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 Citizens' Util. Ratepayer Bd v. State Corp. Comm 'n ofState, 47 Kan. App. 2d 1112, 1131 (2012). | 173 Citizens' Util. Ratepayer Bd v. State Corp. Comm 'n ofState, 47 Kan. App. 2d 1112, 1131 (2012). | ||
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* 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 wil.1 result in rates that are notunduly burdensome, unduly preferential, or unreasonably discriminatory. | * 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 wil.1 result in rates that are notunduly 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. | 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'~ 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 | 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'~ 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 alfordable 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 impr~ve 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). | ||
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 alfordable 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 impr~ve 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 ' | 39 ' | ||
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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 jurisdictiQn ,over the subject matter and parties for the purpose of entering such further orders as it deems necessary. | 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 jurisdictiQn ,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. | BY THE COMMISSION IT IS SO ORDERED. | ||
Albrecht, Chair; Emler, Commissioner; Apple, Commissioner Dated: SEP 2 4 2115 | Albrecht, Chair; Emler, Commissioner; Apple, Commissioner Dated: SEP 2 4 2115 REV/DLK Secretary to the Commission ElVIAILED | ||
REV/DLK Secretary to the Commission ElVIAILED | |||
/ | / | ||
SEP 2 4 2015 215 K.S.A. 66-l 18b; K.S.A. 77-529(a)(l). | SEP 2 4 2015 215 K.S.A. 66-l 18b; K.S.A. 77-529(a)(l). | ||
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.EMAILED SEP 2 4 2015 | .EMAILED SEP 2 4 2015 | ||
SEP 2 4 2015 CERTIFICATE OF SERVICE 15-WSEE-115-RTS 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. | SEP 2 4 2015 CERTIFICATE OF SERVICE 15-WSEE-115-RTS 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 7400 W 110TH ST STE 750 KANSAS CITY, MO 64112 OVERLAND PARK, KS 66210-2362 Fax: 913-451-6205 Fax: 913-661-9863 lhagedorn@polsinelli.com jim@smiz_ak-law.com MARTIN J. BREGMAN, ATTORNEY .DUSTIN BASHFORD, MANAGER - SYSTEM DESIGN STINSON LEONARD STREET LLP TALLGRASS PONY EXPRESS PIPELINE, LLC 1201 WALNUT ST STE 2900 370 Van Gordon Street KANSAS CITY, MO 64106 Lakewood, CO 80228 Fax: 816-691-3495 dustin.bashford@tallgrassenergylp.com marty.bregman@stinsonleonard.com Stefan Evanoff, VICE-PRESIDENT, PIPELINE ADAM SCHICHE, SENIOR ATTORNEY MANAGEMENT TALLGRASS PONY EXPRESS PIPELINE, LLC TALLGRASS P.ONY 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 THQMPSON & KNIGHT LLP THOMPSON & KNIGHT LLP 98 SAN JACINTO BLVD STE 1900 98 SAN JACINTO BLVD STE 1900 AUSTIN, TX 78701 AUSTIN, TX 78701 | 900 W 48TH PLACE STE 900 7400 W 110TH ST STE 750 KANSAS CITY, MO 64112 OVERLAND PARK, KS 66210-2362 Fax: 913-451-6205 Fax: 913-661-9863 lhagedorn@polsinelli.com jim@smiz_ak-law.com MARTIN J. BREGMAN, ATTORNEY .DUSTIN BASHFORD, MANAGER - SYSTEM DESIGN STINSON LEONARD STREET LLP TALLGRASS PONY EXPRESS PIPELINE, LLC 1201 WALNUT ST STE 2900 370 Van Gordon Street KANSAS CITY, MO 64106 Lakewood, CO 80228 Fax: 816-691-3495 dustin.bashford@tallgrassenergylp.com marty.bregman@stinsonleonard.com Stefan Evanoff, VICE-PRESIDENT, PIPELINE ADAM SCHICHE, SENIOR ATTORNEY MANAGEMENT TALLGRASS PONY EXPRESS PIPELINE, LLC TALLGRASS P.ONY 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 THQMPSON & KNIGHT LLP THOMPSON & KNIGHT LLP 98 SAN JACINTO BLVD STE 1900 98 SAN JACINTO BLVD STE 1900 AUSTIN, TX 78701 AUSTIN, TX 78701 | ||
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(10 pages) | (10 pages) | ||
2015.03.24 14:03:41 Kans.35 CorFor.atiori Comri'!ission 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 ) | 2015.03.24 14:03:41 Kans.35 CorFor.atiori Comri'!ission 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 ) | ||
Decominissioning Cost Study as Provided by ) | Decominissioning Cost Study as Provided by ) | ||
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4 Prehearing Officer Order Granting Joint Motion to Conven Evidentiary Hearing to Settlement Hearing (Feb. 11, 2015). | 4 Prehearing Officer Order Granting Joint Motion to Conven Evidentiary Hearing to Settlement Hearing (Feb. 11, 2015). | ||
3 | 3 | ||
: c. Westar, KCP&L, and KEPCo agree to use an escalation rate of 3.15% | : 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 | per year to escalate the 2014 decommissioning cost. estimate of | ||
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_achieved and suggest the Commission adopt the following schedule: | _achieved and suggest the Commission adopt the following schedule: | ||
: i. 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. | : i. 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. | ||
: 11. On or before September 1, 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. | : 11. On or before September 1, 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). | 5 Direct Testimony of Leo M. Haynos, p. 12, lines 8-23 (Jan. 5, 2015). | ||
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6 | 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 h1 rates later should not 14 cause such rates to become unjust or unreasonable. | because the decommissioning cost elements being stipulated to in this docket are fair, reasonable, and fully supported by the evidence, inclusion of the same h1 rates later should not 14 cause such rates to become unjust or unreasonable. | ||
: 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 | : 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 | ||
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: 22. The Commission approves of the Stipulation: in its *entirety, including the portions proposing a procedural schedule for the unresolved issues. The Commissi~:m finds that the Stipulation is supported by substantial, COII!petent evidence, is in the public interest, and will resuhinjust and reasonable rates. | : 22. The Commission approves of the Stipulation: in its *entirety, including the portions proposing a procedural schedule for the unresolved issues. The Commissi~:m finds that the Stipulation is supported by substantial, COII!petent evidence, is in the public interest, and will resuhinjust and reasonable rates. | ||
IT IS, THEREFORE, BY THE COMMISSION ORDERED THAT: | 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; | 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; | ||
* | * | ||
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(4 pages) | (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 23rd day of January, 2018. | STATE OF .MISSOURI PUBLIC SERVICE COMMISSION At a session of the Public Service Commission held at its office in Jefferson City on the 23rd day of January, 2018. | ||
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ORDER APPROVING STIPULATION AND AGREEMENT* | ORDER APPROVING STIPULATION AND AGREEMENT* | ||
Issue Date: January 23, 2018 Effective Date: February 22, 2018 This order approves the stipulation and agreement between Kansas City Power & | Issue Date: January 23, 2018 Effective Date: February 22, 2018 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 | Light Company (KCP&L) and the Staff of the Commission regarding KCP&L's funding for the decommissioning of its Wolf Creek Generating Station. | ||
the decommissioning of its Wolf Creek Generating Station. | |||
Commission rule 4 CSR 240-3.185 (3) states, in part: | 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 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. | ||
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2 | 2 | ||
Having considered the 2017 decommissioning cost study for th~ Wolf Creek Generating Station and the stipulation and agreement, both of which will be received into evidence, the Commission determines that the stipulation and agreement should be approved. In doin.g so, the Commission finds that KCP&L's 2017 cost study satisfies the. | |||
Having considered the 2017 decommissioning cost study for th~ Wolf Creek Generating Station and the stipulation and agreement, both of which will be received into evidence, the Commission determines that the stipulation and agreement should be | |||
approved. In doin.g so, the Commission finds that KCP&L's 2017 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 afthe current level of $1,281,264. The Commission also finds that | 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 afthe current level of $1,281,264. The Commission also finds 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. | . 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. | ||
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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 On August 29, 2014, K~P&L filed in File No, E0-2015-0056 an Application for Approval of the Accrual and Funding of Wolf Creek Gen~rating Station 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 2014 Study, the final shutdown date of Wolf Creek was projected to occur in 2045 . | 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 On August 29, 2014, K~P&L filed in File No, E0-2015-0056 an Application for Approval of the Accrual and Funding of Wolf Creek Gen~rating Station 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 2014 Study, the final shutdown date of Wolf Creek was projected to occur in 2045 . | ||
. The calculations set forth in the 2014 Study were performed in a manner consistent with previous filings. KCP&L's 2014 analysis confirmed the adequacy of the annual funding level of $1,281,264 (Missouri jurisdictional amount), given the 2014 Study's then current . | . The calculations set forth in the 2014 Study were performed in a manner consistent with previous filings. KCP&L's 2014 analysis confirmed the adequacy of the annual funding level of $1,281,264 (Missouri jurisdictional amount), given the 2014 Study's then current . | ||
prediction of decommissioning costs of $765.060 million for the DEGON decommissioning option under what KCP&L believed were a reasonable set of economic, fin~ncial, and investment assumptions. Consequently, KCP&.L did not seek any changes to its funding | prediction of decommissioning costs of $765.060 million for the DEGON decommissioning option under what KCP&L believed were a reasonable set of economic, fin~ncial, and investment assumptions. Consequently, KCP&.L did not seek any changes to its funding level. KCP&L and the Staff entered into a Non-Unanimous Stipulation And Agreement,* | ||
level. KCP&L and the Staff entered into a Non-Unanimous Stipulation And Agreement,* | |||
which Public Counsel did not oppose. | which Public Counsel did not oppose. | ||
As part of the Non-Unanimous Stipulation And Agreement in File No. E0-2015- | As part of the Non-Unanimous Stipulation And Agreement in File No. E0-2015- | ||
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The 2017 Study by TLG includes KCP&L's share of thE3 cost for decommissioning* | The 2017 Study by TLG includes KCP&L's share of thE3 cost for decommissioning* | ||
the Independent Spent Fuel Storage Installation ("ISFSI") at Wolf Creek .. KCP&L's 47% | the Independent Spent Fuel Storage Installation ("ISFSI") at Wolf Creek .. KCP&L's 47% | ||
share of the $6.69 million is $3.14 million (MO and KS) identified in the current decommissioning cost analysis [Document Wll-1741-001, Rev. 0, Table C, cost element 2d.2.4] prepared by TLG Services, Inc., elated August 20*17. 6 The ISFSI will be constructed on the Wolf Creek site to hold the spent nuclear fuel assemblies (high-level | share of the $6.69 million is $3.14 million (MO and KS) identified in the current decommissioning cost analysis [Document Wll-1741-001, Rev. 0, Table C, cost element 2d.2.4] prepared by TLG Services, Inc., elated August 20*17. 6 The ISFSI will be constructed on the Wolf Creek site to hold the spent nuclear fuel assemblies (high-level 4 | ||
DEGON assumes decontaminating and decommissioning immediately foHowing conclusion of power operations in 2045. Work is anticipated to be completed by ~053. DEGON 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 2017 Dollars is | |||
$813,733,000. . | $813,733,000. . | ||
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 NRG. This process is anticipated to be completed by 2106. Total estimated cost to decommission in 2017 Dollars is $1,093,117,000. | 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 NRG. This process is anticipated to be completed by 2106. Total estimated cost to decommission in 2017 Dollars is $1,093,117,000. | ||
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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 fili~g, 8 | 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 fili~g, 8 | ||
STIPULATIONS AND AGREEMENTS The Signatories to this case have reached certain understandings so that the Staff and KCP&L stipulate and agree as follows: | 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 j,urisdictional operations annual decommissioning expense accrual and trust fund payment was initially set by the Commission at | : 1. KCP&L's Missouri retail j,urisdictional operations annual decommissioning expense accrual and trust fund payment was initially set by the Commission at | ||
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, 4. ISFSI funds recovered from the DOE in connection with decommissioning of the ISFSI will be used to offset the costs of decommissioning the ISFSI. | , 4. ISFSI funds recovered from the DOE in connection with decommissioning of the ISFSI will be used to offset the costs of decommissioning the ISFSI. | ||
: 5. Pursuant to 4 CSR 240-20.070(12), excess trust funds from the costs of decommissioning the*Wolf Creek Generating Station and the ISFSl.are to be reimbursed to the ratepayers through the ratemaking process. | : 5. Pursuant to 4 CSR 240-20.070(12), excess trust funds from the costs of decommissioning the*Wolf Creek Generating Station and the ISFSl.are to be reimbursed to the ratepayers through the ratemaking process. | ||
* 6. 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 | * 6. 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 and the ISFSI. | ||
level. The forecasted assumptions include, but are not limited to, capital market expectations, projected decommissioning inflation rates and the costs to decommission Wolf Creek and the ISFSI. | |||
: 7. The Signatories agree that it is reasonable to use capital market return expectation information provided by Great Plains Energy's pension p*lan 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 10 | : 7. The Signatories agree that it is reasonable to use capital market return expectation information provided by Great Plains Energy's pension p*lan 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 10 | ||
. market return expectations or the Gommission finds in a contested case that different | . market return expectations or the Gommission finds in a contested case that different | ||
* ;s'ource and/or meth9dology for capital market return expectation are more appropriate. | * ;s'ource and/or meth9dology for capital market return expectation are more appropriate. | ||
: 8. KCP&L shall continue its Missouri retail jurisdiction expense accruals and | : 8. 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. | ||
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. | |||
: 9. Annual Missouri retail jurisdictional decommissioning costs, inclusive of the . | : 9. Annual Missouri retail jurisdictional decommissioning costs, inclusive of the . | ||
ISFSI, in the amount of $1,281,264 are, and should continue to be, included in KCP&L's | ISFSI, in the amount of $1,281,264 are, and should continue to be, included in KCP&L's | ||
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: 10. . 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 asubsequent rate proceeding. | : 10. . 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 asubsequent rate proceeding. | ||
: 11. The Signatories agree that KCP&L shall continue to record and preserve Wolf yreek 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. | : 11. The Signatories agree that KCP&L shall continue to record and preserve Wolf yreek 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. | ||
* 12. To the extent the Commission belieyes that 4 CSR 240-4.017 applies, KCP&L requests a waiver for good cause of this rule. KCP&L attaches as Exhibit A, a | * 12. To the extent the Commission belieyes that 4 CSR 240-4.017 applies, KCP&L requests a waiver for good cause of this rule. KCP&L attaches as Exhibit A, a verified statement that it had no communication with the Office of the Commission within the prior 150 days to the filing of the Application in File No. E0-2018-0062 regarding-any | ||
verified statement that it had no communication with the Office of the Commission within the prior 150 days to the filing of the Application in File No. E0-2018-0062 regarding-any | |||
\.J substantive issue likely to be in this case. | \.J substantive issue likely to be in this case. | ||
* 11 | * 11 | ||
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Commission authority, decommissioning methodology, ratemaking principle, valuation methodology, cost of service methodology or det~rmination, depreciation principle or method, rate design methodology, cost allocation, cost recovery, or prudence that may underlie this Agreement or for which pro_vision is made ir'.1 this Agreement. | Commission authority, decommissioning methodology, ratemaking principle, valuation methodology, cost of service methodology or det~rmination, depreciation principle or method, rate design methodology, cost allocation, cost recovery, or prudence that may underlie this Agreement or for which pro_vision is made ir'.1 this Agreement. | ||
: 14. 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 accordancewith Sectio!l 536.080.1 RSMo or Art. V, Section 18 Mo. Const. | : 14. 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 accordancewith Sectio!l 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 suggestions or memoranda, testimony or exhibits that may have been offered or received in.support of or in opposition | The Signatories shall retain all procedural and due process rights as fully_ as though this Agreement had not been presented for approval, and any suggestions or memoranda, testimony or exhibits that may have been offered or received in.support of or in opposition to this Agr~ement shall thereupon b_ecome 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 . | |||
to this Agr~ement shall thereupon b_ecome 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 . | |||
. .15. ~o 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. | . .15. ~o 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. | ||
12 | 12 | ||
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6 Q. Why are you using a lower return in your calculation than the return used by Westar 7 witness McGrath? | 6 Q. Why are you using a lower return in your calculation than the return used by Westar 7 witness McGrath? | ||
8 A. We are using the same source for the forecasted return data, but Westar relied on the data 9 published for 201 7 and my calculations use the 2018 edition, which reports lower expected 10 returns than the 2017 forecasts. We are both using Long-Term Capital Market 11 Assumptions (LTCMA) published by J.P. Morgan Asset Management (JPMAM) as our 12 source for expected returns over the long-run (more than ten years) for various asset 13 classes. The following table shows the 2017 and 2018 forecasts for the asset classes used 14 in the NDT and highlights the lowered forecasts. | 8 A. We are using the same source for the forecasted return data, but Westar relied on the data 9 published for 201 7 and my calculations use the 2018 edition, which reports lower expected 10 returns than the 2017 forecasts. We are both using Long-Term Capital Market 11 Assumptions (LTCMA) published by J.P. Morgan Asset Management (JPMAM) as our 12 source for expected returns over the long-run (more than ten years) for various asset 13 classes. The following table shows the 2017 and 2018 forecasts for the asset classes used 14 in the NDT and highlights the lowered forecasts. | ||
J.P. Morgfill Asset_ Managflllent ___ _ | J.P. Morgfill Asset_ Managflllent ___ _ | ||
__ Long~Term_Capital Market_Assump)ions ___ _ | __ Long~Term_Capital Market_Assump)ions ___ _ | ||
| Line 5,456: | Line 5,071: | ||
!Equities-Small Cap 8.67% 7.35% | !Equities-Small Cap 8.67% 7.35% | ||
- )iq~iti;;~futer~ati~~al (EAFE)- 7.61% | - )iq~iti;;~futer~ati~~al (EAFE)- 7.61% | ||
_:c::~_r~ B_9nds__ _ __ ___ _ _ _ :_ 3.44% _ -~ __ 3.§7% | _:c::~_r~ B_9nds__ _ __ ___ _ _ _ :_ 3.44% _ -~ __ 3.§7% | ||
High Yield Bonds . , 6.13% 1 5.59% | High Yield Bonds . , 6.13% 1 5.59% | ||
| Line 5,465: | Line 5,079: | ||
: I | : I | ||
!--- -----~-------- -------- ___ 1 ___ --- --- --- ~ | !--- -----~-------- -------- ___ 1 ___ --- --- --- ~ | ||
ihttps://am.jpmorgan.com/us/institutionaV2018-long-term-capital-market-assumptions | ihttps://am.jpmorgan.com/us/institutionaV2018-long-term-capital-market-assumptions 15 * ' | ||
15 * ' | |||
16 Q. Is ~MAM's publication a reasonable source for these types of forecasts? | 16 Q. Is ~MAM's publication a reasonable source for these types of forecasts? | ||
6 | 6 | ||
| Line 5,499: | Line 5,111: | ||
_!!_pclated Capital Stru-cture via KCC DR#1_59 & 1-8-095 S&A +- | _!!_pclated Capital Stru-cture via KCC DR#1_59 & 1-8-095 S&A +- | ||
*F March 31, 2018 , | *F March 31, 2018 , | ||
-----------r:--- ---------- -: ------ '---r | -----------r:--- ---------- -: ------ '---r 1 | ||
1 | |||
~ | ~ | ||
: Weight l | : Weight l | ||
* l I | * l I | ||
--- - - - - - - - -- - - - - - - --r---- | --- - - - - - - - -- - - - - - - --r---- | ||
Cost | Cost | ||
. J Weighted- | . J Weighted-i | ||
i | |||
* Cost | * Cost | ||
-T-I I | -T-I I | ||
| Line 5,529: | Line 5,135: | ||
- -- ------ Westar Energy -- Rate | - -- ------ Westar Energy -- Rate | ||
- ----of Return | - ----of Return | ||
; Proposed Rate of Return in Section 7 of Application | ; Proposed Rate of Return in Section 7 of Application | ||
__ : Test Year_Ended_Ju~ 30, 2017 Updated to September 30, 2017 | __ : Test Year_Ended_Ju~ 30, 2017 Updated to September 30, 2017 | ||
| Line 5,541: | Line 5,146: | ||
l _- : - | l _- : - | ||
-----------~----- --- - | -----------~----- --- - | ||
7.33%1 | 7.33%1 | ||
______ '.J - | ______ '.J - | ||
| Line 5,552: | Line 5,155: | ||
5 Capital Structure 6 Q. Do you have any adjustments to WR's capital structure? | 5 Capital Structure 6 Q. Do you have any adjustments to WR's capital structure? | ||
7 A. Only that I recommend updating the cost and account balances from September 31, 2017, 8 to March 31, 2018. Westar provided this updated information in response to KCC DR 9 # 159. As displayed in the previous two tables, there is a minor change in the capital ratios 10 from the September 31, 2017, balances to the March 31, 2018. It is reasonable to use the | 7 A. Only that I recommend updating the cost and account balances from September 31, 2017, 8 to March 31, 2018. Westar provided this updated information in response to KCC DR 9 # 159. As displayed in the previous two tables, there is a minor change in the capital ratios 10 from the September 31, 2017, balances to the March 31, 2018. It is reasonable to use the | ||
* 11 March 31, 2018, capital structure because the update better reflects the capital costs and 12 ratios that is financing WR's rate base. The rate of return calculation in Staffs ROR will 13 reflect along-term debt ratio of about48.33% and an equity ratio of51.24% (these numbers | * 11 March 31, 2018, capital structure because the update better reflects the capital costs and 12 ratios that is financing WR's rate base. The rate of return calculation in Staffs ROR will 13 reflect along-term debt ratio of about48.33% and an equity ratio of51.24% (these numbers 14 include some rounding; Staffs Schedule C contains the non-truncated calculations). | ||
14 include some rounding; Staffs Schedule C contains the non-truncated calculations). | |||
15 Q. Is WR's updated capitalization within the range seen in the electric utility industry? | 15 Q. Is WR's updated capitalization within the range seen in the electric utility industry? | ||
16 A. Yes, financially sound electric utilities have traditionally employed capitalization policies 17 of about 50% debt and 50% equity. The group of electric utilities selected ~s the proxy-18 group for my cost of capital analysis follows this same pattern as seen in the following 19 table. | 16 A. Yes, financially sound electric utilities have traditionally employed capitalization policies 17 of about 50% debt and 50% equity. The group of electric utilities selected ~s the proxy-18 group for my cost of capital analysis follows this same pattern as seen in the following 19 table. | ||
| Line 5,635: | Line 5,236: | ||
19 A. A 9.30% return on equity is at the low-end of recent observations for electric utility r*ate 20 cases. For the first quarter of 2018; the average ROE granted was 9.75% with thirteen 13 | 19 A. A 9.30% return on equity is at the low-end of recent observations for electric utility r*ate 20 cases. For the first quarter of 2018; the average ROE granted was 9.75% with thirteen 13 | ||
Direct Testimony of Adam H. Gatewood DocketNo; 18-WSEE-328-RTS 1 observations. 10 Separating out only those decisions associated with vertically integrated 2 electric utilities and not tied to a limited-issue rider brings the number of observations down 3 to five with an average of 9.78%. 11 Over the past decade, allowed returns have declined | Direct Testimony of Adam H. Gatewood DocketNo; 18-WSEE-328-RTS 1 observations. 10 Separating out only those decisions associated with vertically integrated 2 electric utilities and not tied to a limited-issue rider brings the number of observations down 3 to five with an average of 9.78%. 11 Over the past decade, allowed returns have declined 4 nationally, although the rate at which those declines have occurred vary from jurisdiction 5 to jurisdiction. That decline has happened at a more rapid pace in Kansas than in most 6 otherjurisdictions. Over the past several quarters, there appears to *be a plateau in allowed 7 returns; that is the rate of decline has fallen off as shown in the graphs that follow. | ||
4 nationally, although the rate at which those declines have occurred vary from jurisdiction 5 to jurisdiction. That decline has happened at a more rapid pace in Kansas than in most 6 otherjurisdictions. Over the past several quarters, there appears to *be a plateau in allowed 7 returns; that is the rate of decline has fallen off as shown in the graphs that follow. | |||
8 Q: Please provide sonie background on how Staff arrived at the 9.30% ROE for the 9 ERSP. | 8 Q: Please provide sonie background on how Staff arrived at the 9.30% ROE for the 9 ERSP. | ||
10 A. Staff was searching for a productive and fair settlement position for the 18-095 Merger, 11 which led Staff to consider a rate moratorium and.a sharing mechanism of earnings above 12 an allowed return. Thus, it was necessary for Staff to perform a fresh and thorough analysis 13 of capital costs to determine the appropriate threshold for measuring earnings. At that time, 14 we were also aware that both Westar and KCP&L would be filing rate cases in 2018 and 15 | 10 A. Staff was searching for a productive and fair settlement position for the 18-095 Merger, 11 which led Staff to consider a rate moratorium and.a sharing mechanism of earnings above 12 an allowed return. Thus, it was necessary for Staff to perform a fresh and thorough analysis 13 of capital costs to determine the appropriate threshold for measuring earnings. At that time, 14 we were also aware that both Westar and KCP&L would be filing rate cases in 2018 and 15 | ||
| Line 5,648: | Line 5,247: | ||
: 7. .settlement in which Westar's ROE was about 9.35%. Thus, the cost of capital. analysis 8 provided Staff with the position that KCPL's and Westar's ROE could remain in place 9 from their last rate cases to be used for the ERSP and setting rates in their 2018 rate cases. | : 7. .settlement in which Westar's ROE was about 9.35%. Thus, the cost of capital. analysis 8 provided Staff with the position that KCPL's and Westar's ROE could remain in place 9 from their last rate cases to be used for the ERSP and setting rates in their 2018 rate cases. | ||
10 Q. If the parties to the 18-095 S&A agreed to support a 9.30% ROE in this Docket, why 11 did you perform a new cost of capital study? | 10 Q. If the parties to the 18-095 S&A agreed to support a 9.30% ROE in this Docket, why 11 did you perform a new cost of capital study? | ||
12 A. I did this to provide the Commission with. a comparative record on wh~ch to base its 13 decision and to establish facts that demonstrate an ROE of 9.30% is a just and reasonable 14 return | 12 A. I did this to provide the Commission with. a comparative record on wh~ch to base its 13 decision and to establish facts that demonstrate an ROE of 9.30% is a just and reasonable 14 return in determining Westar's revenue requirement. The signatories to the 18-095 S&A | ||
in determining Westar's revenue requirement. The signatories to the 18-095 S&A | |||
. \ | . \ | ||
15 are very much aware that we cannot make a decision for the.Commission. Ultimately, it 16 is the Commission that has to r.eview the evidence and decide if 9.30% is a just and 17 reasonable return for setting Westar's revenue requirement.. The legal standards that I 18 discuss later s~ill apply to the Commission's decision, regardless of the fact that several 19 parties have re;iched an agreement on the issue. | 15 are very much aware that we cannot make a decision for the.Commission. Ultimately, it 16 is the Commission that has to r.eview the evidence and decide if 9.30% is a just and 17 reasonable return for setting Westar's revenue requirement.. The legal standards that I 18 discuss later s~ill apply to the Commission's decision, regardless of the fact that several 19 parties have re;iched an agreement on the issue. | ||
| Line 5,718: | Line 5,315: | ||
}Using Short-Term Grow~EPS _q_~owth & ---- | }Using Short-Term Grow~EPS _q_~owth & ---- | ||
JLong-Term nGDP Forecast | JLong-Term nGDP Forecast | ||
~=---r------+ --~:--r -~-~- j | ~=---r------+ --~:--r -~-~- j I , i i-1------ -- -- --- --- -- .----- --------------- _L_ _______l_____ _ L ________ j__ | ||
I , i i-1------ -- -- --- --- -- .----- --------------- _L_ _______l_____ _ L ________ j__ | |||
-;- _____________ ~apital Asset Pricing M~de,Is - ~ - ____ --t I | -;- _____________ ~apital Asset Pricing M~de,Is - ~ - ____ --t I | ||
-i--- | -i--- | ||
i I | i I | ||
.---~----r : | .---~----r : | ||
| Line 5,736: | Line 5,329: | ||
:1.~._ | :1.~._ | ||
I Morgan Asset Management (2018 edition) ' | I Morgan Asset Management (2018 edition) ' | ||
* i | * i 1 | ||
2 Q. For a point of comparison, please summarize return on equity decisions by this 3 Commission and Commissions across the country? | |||
4 A. The first table contains allowed return on equity decisions made by this Commission in 5 litigated rate cases. As a point of reference to the prevailing capital markets at that time, I 6 included the yield on the Baa rated corporate bonds as of the month of the Commission's 7 decision. | 4 A. The first table contains allowed return on equity decisions made by this Commission in 5 litigated rate cases. As a point of reference to the prevailing capital markets at that time, I 6 included the yield on the Baa rated corporate bonds as of the month of the Commission's 7 decision. | ||
22 | 22 | ||
| Line 5,778: | Line 5,370: | ||
10.00% *.*.*** .*.. | 10.00% *.*.*** .*.. | ||
9.50%, | 9.50%, | ||
9.00% | 9.00% | ||
8.50% | 8.50% | ||
8.00%, | 8.00%, | ||
7.50% -- -** - --- | 7.50% -- -** - --- | ||
7.00% | 7.00% | ||
6 ..50~~ | 6 ..50~~ | ||
- --- -- ---~--;._-_-_ --- -------------- | - --- -- ---~--;._-_-_ --- -------------- | ||
----**~.-.. | ----**~.-.. | ||
6.00% -*- -- -- - *- ----* ----- ---- -----*------------- | 6.00% -*- -- -- - *- ----* ----- ---- -----*------------- | ||
5.50% ----------- --- -- ------- -*-------- ---------*------------- -- | 5.50% ----------- --- -- ------- -*-------- ---------*------------- -- | ||
5.00% | 5.00% | ||
4.50% -- - - -- -- -- --------- ------------*.- . --------- - - - - - - - - - - - - - - | 4.50% -- - - -- -- -- --------- ------------*.- . --------- - - - - - - - - - - - - - - | ||
* 4.00% | * 4.00% | ||
| Line 5,818: | Line 5,400: | ||
6.00% - __ . - --- -- - :. | 6.00% - __ . - --- -- - :. | ||
5.50% -- | 5.50% -- | ||
*****~*~ *-*-* *-~- | *****~*~ *-*-* *-~- | ||
5.00% | 5.00% | ||
4.50% | 4.50% | ||
4.00% | 4.00% | ||
eBaa Corporate Yield .A.Median ROE 3 | eBaa Corporate Yield .A.Median ROE 3 | ||
4 Q. How does Staff's recommendation compare to the returns available on other 5 investments? | 4 Q. How does Staff's recommendation compare to the returns available on other 5 investments? | ||
| Line 5,863: | Line 5,436: | ||
-- --- Jul::.!7 __ . __ _b~_. _____ 3.99%,. 4.31% --- '!_.40~t- 3.82%* | -- --- Jul::.!7 __ . __ _b~_. _____ 3.99%,. 4.31% --- '!_.40~t- 3.82%* | ||
Jun-17 2.80%, 3.94% | Jun-17 2.80%, 3.94% | ||
4.28% 4.38%, | 4.28% 4.38%, | ||
-----+- | -----+- | ||
3.85%' | 3.85%' | ||
May-17 ' 2.96% 4.12% 4.48% 4.56%* 4.04% | May-17 ' 2.96% 4.12% 4.48% 4.56%* 4.04% | ||
___*Average 2_2Q~~- 3.97%, +/-_28_o/o__ _ __ 4.39% 3.85%' | ___*Average 2_2Q~~- 3.97%, +/-_28_o/o__ _ __ 4.39% 3.85%' | ||
Risk Premiums Over Fixed Income Securities KCC Staff's Recommended ROE | Risk Premiums Over Fixed Income Securities KCC Staff's Recommended ROE 9.30% | ||
9.30% | |||
Average Yield on 30 Year Treasury_!3o_nd,_*_ _2_.9_0_o/c_o_ ___, | Average Yield on 30 Year Treasury_!3o_nd,_*_ _2_.9_0_o/c_o_ ___, | ||
Equity Risk Premium Ove_r the 30-Year T!."asury Bond Yield 6.40% | Equity Risk Premium Ove_r the 30-Year T!."asury Bond Yield 6.40% | ||
KCC Staff's Recommended ROE 9.30% | |||
KCC Staff's Recommended ROE | |||
9.30% | |||
------ __ Average Yield on "A" Rated Utility)3_on__d_s_____3_._97_o/c_*_----, | ------ __ Average Yield on "A" Rated Utility)3_on__d_s_____3_._97_o/c_*_----, | ||
Equity Risk Premium_Over "A" Utility~nd Yield. 5.33% | Equity Risk Premium_Over "A" Utility~nd Yield. 5.33% | ||
| Line 5,890: | Line 5,455: | ||
KCC | KCC | ||
- - , __Recommended Staff's - - -- -- *- | - - , __Recommended Staff's - - -- -- *- | ||
ROE | ROE 9.30% | ||
9.30% | |||
Average Yield on Westar Bonds ___3_.8_5_o/c_o_ _ | Average Yield on Westar Bonds ___3_.8_5_o/c_o_ _ | ||
Premium over Yield on Westar Bonds 5.45% | Premium over Yield on Westar Bonds 5.45% | ||
| Line 5,953: | Line 5,516: | ||
J.._Alliant Energy Corl} --- -- - - | J.._Alliant Energy Corl} --- -- - - | ||
,Ameren Corp | ,Ameren Corp | ||
---+-~_-_E_ - | ---+-~_-_E_ - | ||
'.ALE IA3 | '.ALE IA3 | ||
| Line 5,965: | Line 5,527: | ||
Jx t- 74.9%1 | Jx t- 74.9%1 | ||
_:x_ . ___ ], ____ 85.6% | _:x_ . ___ ], ____ 85.6% | ||
s2~o/~~ | s2~o/~~ | ||
86.0% __ . 85.0%1 _ | 86.0% __ . 85.0%1 _ | ||
'American Electric Power Company Inc ~EP ,B¥1_ I~- . Yes x x I "- : 86,7% 9_+/-.)~i | 'American Electric Power Company Inc ~EP ,B¥1_ I~- . Yes x x I "- : 86,7% 9_+/-.)~i | ||
.~,;;;,~IGR-mln;:*_* - - - * * .A_G_!l_. jB~I_ ~!3B+ _ Yes x x " ~LO%j 85._7o/o' | .~,;;;,~IGR-mln;:*_* - - - * * .A_G_!l_. jB~I_ ~!3B+ _ Yes x x " ~LO%j 85._7o/o' | ||
| Line 6,047: | Line 5,607: | ||
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 reduction signals maJor change in ongoing operations and is probably a sign that 2 managements cannot expect stable eammgs growth in the foreseeable years. Such 3 candidates should not be in the proxy group for W_estar because that situation 1s not 4 consistent with Westar's prospects. Pacific Gas & Electric is the only utility eliminated 5 with this criteria; it suspended its dividend payments in December of 201 7. | Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 reduction signals maJor change in ongoing operations and is probably a sign that 2 managements cannot expect stable eammgs growth in the foreseeable years. Such 3 candidates should not be in the proxy group for W_estar because that situation 1s not 4 consistent with Westar's prospects. Pacific Gas & Electric is the only utility eliminated 5 with this criteria; it suspended its dividend payments in December of 201 7. | ||
6 The criteria in columns mne and ten attempt to ascertain whether providing regulated 7 electric utilities services is the primary business of the company. I set the threshold for 8 revenl!es from electric utility service at 70% of total revenues. This is a subjective cutoff, 9 but it works for this analysis because meeting that threshold means that the company is 10 largely focused on, and earnings are ~erived from, providing regulated electric utility 11 services. The following table contains Staffs proxy group of 14 electric utilities for the 12 cost of equity and capital structure analyses. | 6 The criteria in columns mne and ten attempt to ascertain whether providing regulated 7 electric utilities services is the primary business of the company. I set the threshold for 8 revenl!es from electric utility service at 70% of total revenues. This is a subjective cutoff, 9 but it works for this analysis because meeting that threshold means that the company is 10 largely focused on, and earnings are ~erived from, providing regulated electric utility 11 services. The following table contains Staffs proxy group of 14 electric utilities for the 12 cost of equity and capital structure analyses. | ||
2 j 4 __?-_ J 6 7 8 9 10 | 2 j 4 __?-_ J 6 7 8 9 10 | ||
*uFERC Selection Criteria*.. . __ _ _ ___ * *Kee Staff Screens* | *uFERC Selection Criteria*.. . __ _ _ ___ * *Kee Staff Screens* | ||
| Line 6,143: | Line 5,702: | ||
+-_____ ___ _____ | +-_____ ___ _____ | ||
*j | *j | ||
___ _____L___ | ___ _____L___ | ||
____L I Di\'.!dendY~tJr'lfii!Jftl!Y7,~_!~ | ____L I Di\'.!dendY~tJr'lfii!Jftl!Y7,~_!~ | ||
J__ | J__ | ||
| Line 6,190: | Line 5,746: | ||
*---** yield | *---** yield | ||
--- available | --- available | ||
-,*- --- from *-r time- period | -,*- --- from *-r time- period 1 | ||
2 Forecasted Growth Rates for the DCF Model 3 Q. Please discuss the importance of the second component, the growth rate (g), in the 4 DCF equation. | |||
5 A. The "g" represents the anticipated annual growth rate in cash-flows that investors expect 6 to receive througl). dividends from the stock. This is a challenging and contentious issue in 7 a DCF analysis for two reasons. First, it is a key element in the DCF model or any form 8 of a discounted cash flow arialysis because the growth rate has a one-for-one effect on the 9 required return produced by the model. All other factors being equal, a higher growth rate 10 results in an equally higher return on equity for the utility. Second, there is an element of 39 | 5 A. The "g" represents the anticipated annual growth rate in cash-flows that investors expect 6 to receive througl). dividends from the stock. This is a challenging and contentious issue in 7 a DCF analysis for two reasons. First, it is a key element in the DCF model or any form 8 of a discounted cash flow arialysis because the growth rate has a one-for-one effect on the 9 required return produced by the model. All other factors being equal, a higher growth rate 10 results in an equally higher return on equity for the utility. Second, there is an element of 39 | ||
| Line 6,252: | Line 5,807: | ||
-fj Social Security Administration (SSA) | -fj Social Security Administration (SSA) | ||
OADSI Trustees Re~rt 2017 : 2095 t' | OADSI Trustees Re~rt 2017 : 2095 t' | ||
L 4.41 % I J ~~ ===~ ... -~~~=~. Av, .~I Additional GDP Estimates | L 4.41 % I J ~~ ===~ ... -~~~=~. Av, .~I Additional GDP Estimates | ||
-~;;;M~2017_ Outlook for Energy 2015 - 2040---r _-- --- - -r I | -~;;;M~2017_ Outlook for Energy 2015 - 2040---r _-- --- - -r I | ||
| Line 6,299: | Line 5,853: | ||
~- _________ ________ _______ j_ _____ :_ ---------~ __ faerageofeachcoltnnnl _7.79%! __ 8.64o/~ | ~- _________ ________ _______ j_ _____ :_ ---------~ __ faerageofeachcoltnnnl _7.79%! __ 8.64o/~ | ||
_Jr _ _ ___ __ _ __ ___ __ _ I L _ ______ 1_ Average ofall observations I_ _-~--------f 1 __ __ ________ 1 _ _ _ I________ j___Rangeofallobservatio;;i ~:~§.o/~ 1- _?:?lCYo_l 1 _________________________ . _; _ _ _ _ _ _ _ _ _ j _______ I______ ________ 1 | _Jr _ _ ___ __ _ __ ___ __ _ I L _ ______ 1_ Average ofall observations I_ _-~--------f 1 __ __ ________ 1 _ _ _ I________ j___Rangeofallobservatio;;i ~:~§.o/~ 1- _?:?lCYo_l 1 _________________________ . _; _ _ _ _ _ _ _ _ _ j _______ I______ ________ 1 | ||
_ ! 1) 2018 annual dividend divided by maximum price observed (5/8/2017 through 5/7/2017) _ | _ ! 1) 2018 annual dividend divided by maximum price observed (5/8/2017 through 5/7/2017) _ | ||
' 2) 2018 annual dividend divided by minimum price observed (5/8/2017 through 5/7/2018) 43)ForecastedEPSgro~h _______ | ' 2) 2018 annual dividend divided by minimum price observed (5/8/2017 through 5/7/2018) 43)ForecastedEPSgro~h _______ | ||
1 | 1 | ||
-~ _______ | -~ _______ | ||
:4) Low-end estimate = col 1 + col 3 _ _ _ ._ , , | :4) Low-end estimate = col 1 + col 3 _ _ _ ._ , , | ||
, - - - - - - - - - - - - - - - * -- *1 - - - ,. - - l-- - -- -- - | , - - - - - - - - - - - - - - - * -- *1 - - - ,. - - l-- - -- -- - | ||
| Line 6,329: | Line 5,877: | ||
t- Staff Proxy Group~- ______ . __ _ _________ _ | t- Staff Proxy Group~- ______ . __ _ _________ _ | ||
Growth Rate Summai-), ___ _______ _________________ + | Growth Rate Summai-), ___ _______ _________________ + | ||
18-WSEE-328-RTS | 18-WSEE-328-RTS 1 | ||
i ' I | |||
*j | *j | ||
-,~- - | -,~- - | ||
| Line 6,341: | Line 5,888: | ||
;Thomson FactSet I Short-run Long-term t'J_- ______ ji_ | ;Thomson FactSet I Short-run Long-term t'J_- ______ ji_ | ||
11 DCF | 11 DCF | ||
, EPS '!DPS I EPS I DPS EPS : DPS I EPS EPS I Avera e nGDP Growth Rate | , EPS '!DPS I EPS I DPS EPS : DPS I EPS EPS I Avera e nGDP Growth Rate | ||
:;\Ile~ Jnc. __ ~AJ-1:= \ l.5_Q_'1'ol _3.50~J ~2Q'Yi_ LO.OJ~ 4_.5_0_'l:~ 4:50% ~0%1 6.~o/oj_ 5.48% 4.30% - | :;\Ile~ Jnc. __ ~AJ-1:= \ l.5_Q_'1'ol _3.50~J ~2Q'Yi_ LO.OJ~ 4_.5_0_'l:~ 4:50% ~0%1 6.~o/oj_ 5.48% 4.30% - | ||
| Line 6,396: | Line 5,942: | ||
~ | ~ | ||
-t--- _ | -t--- _ | ||
Sta~Proxy Group--: *. | Sta~Proxy Group--: *. | ||
Internal Rate of Return (IRR) Results _ | Internal Rate of Return (IRR) Results _ | ||
18-WSEE-328-RTS | 18-WSEE-328-RTS | ||
-1 __ | -1 __ | ||
IAiletelnc ~ 7.68%1 IAlliant EnergySo/p ___ --- __ ___ - J.()Oo/~ _ | IAiletelnc ~ 7.68%1 IAlliant EnergySo/p ___ --- __ ___ - J.()Oo/~ _ | ||
1Ameren Corp I 7.98% | 1Ameren Corp I 7.98% | ||
| Line 6,409: | Line 5,953: | ||
- - -- -- ---- i --9.08% I - | - - -- -- ---- i --9.08% I - | ||
-f- --------------- | -f- --------------- | ||
Edison International ---*- -- - - ------ --,------ I 8.03% --- | Edison International ---*- -- - - ------ --,------ I 8.03% --- | ||
El Paso -Electric Co I 7.25% | El Paso -Electric Co I 7.25% | ||
| Line 6,440: | Line 5,983: | ||
20 Beta 21 The beta coefficient measures the volatility of the return earned by the utility's stock 22 relative to the volatility of the returns earned by the broader equity market. The broad 52 | 20 Beta 21 The beta coefficient measures the volatility of the return earned by the utility's stock 22 relative to the volatility of the returns earned by the broader equity market. The broad 52 | ||
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 equity market is frequently measured using the S&P 500 Index. This measure provides a 2 look at the risk and volatility of a stock relative to other investments. A stock with a beta 3 of 1 is equally as volatile as the | Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 equity market is frequently measured using the S&P 500 Index. This measure provides a 2 look at the risk and volatility of a stock relative to other investments. A stock with a beta 3 of 1 is equally as volatile as the market as a whole. A stock . | ||
market as a whole. A stock . | |||
with a beta of 0.5 is half as 4 volatile as the market. Value-Line reports that Westar has a beta coefficient of0.70. These 5 are similar to the average for the proxy group of 0.67. | with a beta of 0.5 is half as 4 volatile as the market. Value-Line reports that Westar has a beta coefficient of0.70. These 5 are similar to the average for the proxy group of 0.67. | ||
6 Rm 7 Rm is the expected return on the stock market as measured by a broad market index such 8 as the S&P 500~ This represents the total return consisting of the price change of the index 9 plus dividends earned for the year. | 6 Rm 7 Rm is the expected return on the stock market as measured by a broad market index such 8 as the S&P 500~ This represents the total return consisting of the price change of the index 9 plus dividends earned for the year. | ||
| Line 6,456: | Line 5,997: | ||
3 of that exhibited by the broad market and, accordingly, investors would expect a relatively 4 lower return from stocks of public utilities than the broad market. This is a clear indication 5 that public utility companies like Applicants and the proxy group are less volatile (and less 6 risky) than the broad stock market, and investors expect a return lower than that expected 7 of the market. Reviewing the high and low beta.coefficients observed in the proxy group 8 provides a picture of the range that the new company could exhibit in the future. | 3 of that exhibited by the broad market and, accordingly, investors would expect a relatively 4 lower return from stocks of public utilities than the broad market. This is a clear indication 5 that public utility companies like Applicants and the proxy group are less volatile (and less 6 risky) than the broad stock market, and investors expect a return lower than that expected 7 of the market. Reviewing the high and low beta.coefficients observed in the proxy group 8 provides a picture of the range that the new company could exhibit in the future. | ||
, Beta Coefficients, Starrs Proxy Group , | , Beta Coefficients, Starrs Proxy Group , | ||
Updated on May 10, 2018 i | |||
Updated on May 10, 2018 | |||
i | |||
18-WSEE-328-RTS I | 18-WSEE-328-RTS I | ||
_ :Allete me ____ _ )_!.LE __ 0.75/-- | _ :Allete me ____ _ )_!.LE __ 0.75/-- | ||
_ _.~l}i!lf!t EnergyS<?_l))_ :LNT 0.701 | _ _.~l}i!lf!t EnergyS<?_l))_ :LNT 0.701 | ||
;i\tner~n_g~gJ__ _ _ AEE 0.65' American Electric | ;i\tner~n_g~gJ__ _ _ AEE 0.65' American Electric Power Co me AEP Q.65: _ | ||
Power Co me AEP Q.65: _ | |||
. Consolidated Edison me __ ,ED __ -0.50! | . Consolidated Edison me __ ,ED __ -0.50! | ||
__ :'._J_ __ | __ :'._J_ __ | ||
-- :~uke E}!e.r_g_y C~~_!-J~w | -- :~uke E}!e.r_g_y C~~_!-J~w | ||
*Edison mternational ---- -- - | *Edison mternational ---- -- - | ||
,DUK | ,DUK | ||
'iix- Q:m-* | 'iix- Q:m-* | ||
0.60, El | 0.60, El Paso -Electric --- -- | ||
Paso -Electric --- -- | |||
Co EE 0.75 IDACORP me IDA 0:7Q:_ | Co EE 0.75 IDACORP me IDA 0:7Q:_ | ||
NorthWe~~ern_ Corp NWE 0.6?; | NorthWe~~ern_ Corp NWE 0.6?; | ||
| Line 6,491: | Line 6,022: | ||
-1 we~~~- ----------- ---- 1- ---- --- | -1 we~~~- ----------- ---- 1- ---- --- | ||
--IS-o~c~-: Valu;-ii~e-Investm~nt Survey -- --- - | --IS-o~c~-: Valu;-ii~e-Investm~nt Survey -- --- - | ||
9 I' 10 Q. Please describe the forecasted CAPM analysis. | 9 I' 10 Q. Please describe the forecasted CAPM analysis. | ||
54 | 54 | ||
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 A. For the forecasted CAPM, I relied on the expected returns published by JPMAM in its 2 annual publication, Long-Term Capital Market Assumptions for 2018, to establish the 3 expected return for the market. JPMAM publishes 10 to 15-year forecasts of expe"cted 4 returns on dozens of investment asset classes in its annual publication, the Long Term 5 Capital Market Return Assumptions (LTCMRA). JPMAM forecasts an animal return on 6 common stocks of 6.93%. The JPMAM's forecasted returns on common stocks has 7 declined over the past two years; generally a product of the increase in stock prices over 8 the past two years. | Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 A. For the forecasted CAPM, I relied on the expected returns published by JPMAM in its 2 annual publication, Long-Term Capital Market Assumptions for 2018, to establish the 3 expected return for the market. JPMAM publishes 10 to 15-year forecasts of expe"cted 4 returns on dozens of investment asset classes in its annual publication, the Long Term 5 Capital Market Return Assumptions (LTCMRA). JPMAM forecasts an animal return on 6 common stocks of 6.93%. The JPMAM's forecasted returns on common stocks has 7 declined over the past two years; generally a product of the increase in stock prices over 8 the past two years. | ||
9 Following the calculations arid inputs through the CAPM equation in line | 9 Following the calculations arid inputs through the CAPM equation in line 2 of the following 10 table, the forecasted return on a risk-free investment, 10-Year U.S. Treasury Bonds, is 11 subtracted from the- expected return on common stocks resulting in a risk premium of 12 3.86%. This risk premium is the additional return necessary to induce investors to take on 13 the added risk associat~d with common stocks over the risk-free investment. The beta 14 coefficient is applied to the risk premium to ascertain how much of a risk premium is 15 necessary for investors to take on risks of investing in utility stocks as opposed to the risk-16 free U.S. Treasury Bond. | ||
2 of the following 10 table, the forecasted return on a risk-free investment, 10-Year U.S. Treasury Bonds, is 11 subtracted from the- expected return on common stocks resulting in a risk premium of 12 3.86%. This risk premium is the additional return necessary to induce investors to take on 13 the added risk associat~d with common stocks over the risk-free investment. The beta 14 coefficient is applied to the risk premium to ascertain how much of a risk premium is 15 necessary for investors to take on risks of investing in utility stocks as opposed to the risk-16 free U.S. Treasury Bond. | |||
55 | 55 | ||
| Line 6,517: | Line 6,045: | ||
1I I | 1I I | ||
1 : | 1 : | ||
* 6.30% | * 6.30% | ||
. r - | . r - | ||
| Line 6,528: | Line 6,054: | ||
l j_2) Forecasted_ 10 to 15-year annual arithmetic return on intermediate term 1 | l j_2) Forecasted_ 10 to 15-year annual arithmetic return on intermediate term 1 | ||
_(__iU.S. Government bonds by J.P. MorganAssetManageiyent, 2018 Edition , i l3)JResultingriskpremium(l-2) 1 | _(__iU.S. Government bonds by J.P. MorganAssetManageiyent, 2018 Edition , i l3)JResultingriskpremium(l-2) 1 | ||
***+ | ***+ | ||
I 0 | I 0 | ||
| Line 6,568: | Line 6,093: | ||
\ I , | \ I , | ||
'-----~-- __ 1__- _ *t__*_---_____ :*-_____ i .. | '-----~-- __ 1__- _ *t__*_---_____ :*-_____ i .. | ||
*r _ _ r--_---____ :__ _ | *r _ _ r--_---____ :__ _ | ||
~ .. - - - --. .. ,.' | ~ .. - - - --. .. ,.' | ||
I | I | ||
| Line 6,621: | Line 6,144: | ||
25 2042 $ 7,793,513 $ - $ 38,298,060 $ 954,922,646 4.20% | 25 2042 $ 7,793,513 $ - $ 38,298,060 $ 954,922,646 4.20% | ||
26 2043 $ 7,793,513 $ - $ 40,232,062 $ ' . 1,002,948,221 4.20% | 26 2043 $ 7,793,513 $ - $ 40,232,062 $ ' . 1,002,948,221 4.20% | ||
27 28 29 2044 2045 2046 7,793,513 $ | |||
27 28 29 2044 2045 2046 | |||
7,793,513 $ | |||
(78,411,865) | (78,411,865) | ||
(169,068,348) | (169,068,348) 42,247,215 44,183,416 42,747,191 1,052,988,949 1,018,760,500 892,439,343 4.20% | ||
42,247,215 44,183,416 42,747,191 | |||
1,052,988,949 1,018,760,500 892,439,343 4.20% | |||
4.20% | 4.20% | ||
4.20'l;o 30 2047 $ - $ (183,090,767) $ 37,446,755 $ 746,795,331 4.20% | 4.20'l;o 30 2047 $ - $ (183,090,767) $ 37,446,755 $ 746,795,331 4.20% | ||
| Line 6,700: | Line 6,205: | ||
25 2042 $ 8,693,911 $' $ 39,763,722 $ 991,76,8,492 4.20% | 25 2042 $ 8,693,911 $' $ 39,763,722 $ 991,76,8,492 4.20% | ||
26 2043 $ 8,693,911 $ $ 41,797,004 $ 1,042,259,407 4.20% | 26 2043 $ 8,693,911 $ $ 41,797,004 $ 1,042,259,407 4.20% | ||
27 28 2044 2045 8,693,911 $ | |||
$ (63,088,403) 43,915,603 45,940,700 $ | |||
27 28 2044 2045 | |||
8,693,911 $ | |||
$ (63,088,403) | |||
43,915,603 45,940,700 $ | |||
1,094,868,92 I 1,077,721,218 4.20% | 1,094,868,92 I 1,077,721,218 4.20% | ||
4.20% | 4.20% | ||
| Line 6,817: | Line 6,314: | ||
TIMELINESS 2 Raised 3/2/18 High: 55.0 54.3 35.3 29.9 34.1 35.3 37.3 48.1 46.8 54.1 64.9 59.0 Target Price Range Low: 47.1 25.5 19.5 23.1 25.5 28.4 30.6 35.2 37.3 41.5 51.4 51.9 2021 2022 2023 SAFETY 2 Raised 6/20/14 LEGENDS TECHNICAL 3 Lowered 2/23/18 - ~::d~vi1;t~1:sf ~~te | TIMELINESS 2 Raised 3/2/18 High: 55.0 54.3 35.3 29.9 34.1 35.3 37.3 48.1 46.8 54.1 64.9 59.0 Target Price Range Low: 47.1 25.5 19.5 23.1 25.5 28.4 30.6 35.2 37.3 41.5 51.4 51.9 2021 2022 2023 SAFETY 2 Raised 6/20/14 LEGENDS TECHNICAL 3 Lowered 2/23/18 - ~::d~vi1;t~1:sf ~~te | ||
, . , . Relative ~rice Strength 80 BETA .65 (1.00 = Market) .,,.._ | , . , . Relative ~rice Strength 80 BETA .65 (1.00 = Market) .,,.._ | ||
*--... *-- . ' ,. 60 | *--... *-- . ' ,. 60 1,111 O~~~~!/i,~a indicates recession ,...__ 50 2021-23 PROJECTIONS Ann'I Total ....:_.:: ~..*}..... n "- I - J__./ 11 | ||
1,111 O~~~~!/i,~a indicates recession ,...__ 50 2021-23 PROJECTIONS Ann'I Total ....:_.:: ~..*}..... n "- I - J__./ 11 | |||
/ | / | ||
11111* 1 .. 1*'!11111'* | 11111* 1 .. 1*'!11111'* | ||
,. f'T';. | ,. f'T';. | ||
. *-111 1 | . *-111 1 | ||
40 Price Gain Return I I 11* 1 1,**111*1 30 | 40 Price Gain Return I I 11* 1 1,**111*1 30 | ||
* I I High 60 (+10%l 6% 25 Low 45 (-15% Nil I 'Ith, | * I I High 60 (+10%l 6% 25 Low 45 (-15% Nil I 'Ith, | ||
...... ..**** .... ......... ... 20 | ...... ..**** .... ......... ... 20 Insider Decisions I l .... 15 MJJASO N D J to Buy 000000 o o o Options 010000 0 021 I l ****** 10 tos,u 0 1 0 0 0 0 1 0 0 I I 1-7.5 | ||
Insider Decisions I l .... 15 MJJASO N D J to Buy 000000 o o o Options 010000 0 021 I l ****** 10 tos,u 0 1 0 0 0 0 1 0 0 I I 1-7.5 | |||
% TOT. RETURN 2/18 I .. | % TOT. RETURN 2/18 I .. | ||
Institutional Decisions THIS I 11 I 11, .. VLARITH.' | Institutional Decisions THIS I 11 I 11, .. VLARITH.' | ||
*m*m I~ | *m*m I~ | ||
| Line 6,871: | Line 6,362: | ||
I I | I I | ||
. , "'''"111.11 | . , "'''"111.11 | ||
~t)~~;itO=~h=i~=~:=/'ci~s:ea~in:d'j 1 | ~t)~~;itO=~h=i~=~:=/'ci~s:ea~in:d'j 1 | ||
9% l.,c,-,-,,-:-,,t"f----'"--il""""'"'"*11-,.+-.-+1-+-~-.,.,.,-,.,,1"."i 1 | 9% l.,c,-,-,,-:-,,t"f----'"--il""""'"'"*11-,.+-.-+1-+-~-.,.,.,-,.,,1"."i 1 | ||
1 | 1 | ||
/ | / | ||
*''", 11,1** | *''", 11,1** | ||
1 | 1 | ||
,, 11111111 ' ~ - '*'"" . :3~~+/-~~---f~~~=r::::j==+/-=j==+/-==t: | ,, 11111111 ' ~ - '*'"" . :3~~+/-~~---f~~~=r::::j==+/-=j==+/-==t: | ||
*ca[te=s=re=ce=ss[ion~=t=+/-=ar-::+/-~ __ _ | *ca[te=s=re=ce=ss[ion~=t=+/-=ar-::+/-~ __ _ | ||
,l"'""'l'lrrih-rn,.,;,"'-.1!f-....:...~f- ----+---f-----+---f-----+---f-----+- --!---+ 40 48 32 | ,l"'""'l'lrrih-rn,.,;,"'-.1!f-....:...~f- ----+---f-----+---f-----+---f-----+- --!---+ 40 48 32 | ||
'"'l~n-si~d~e-r=D-ec~i-si~o~n-s~--....,,** ******* ** *** ***--1~**!1 1111i! 24 toBuy M J J A S O N D J o o o o o O o o o | '"'l~n-si~d~e-r=D-ec~i-si~o~n-s~--....,,** ******* ** *** ***--1~**!1 1111i! 24 toBuy M J J A S O N D J o o o o o O o o o | ||
| Line 6,955: | Line 6,442: | ||
~=~====~====~~~~=~====~====~~===jt:::j==~:~====j====jt====t::::t:::~t | ~=~====~====~~~~=~====~====~~===jt:::j==~:~====j====jt====t::::t:::~t | ||
.,. /"'--.. - .._ ~ ,,,,,.,_ , _ | .,. /"'--.. - .._ ~ ,,,,,.,_ , _ | ||
- - - * - - - * - * . 64 | - - - * - - - * - * . 64 | ||
~~O | ~~O I 2021-23 PROJECTIONS l,TITn+r;;,,1-+1'!,J...,'l-a-t+-+'-f---l::;;;,'/"---t---t,-..W."1,Uop.!!J''"LU,,l ""fl!'lf-l'.!,1,.'ltH! | ||
I 2021-23 PROJECTIONS l,TITn+r;;,,1-+1'!,J...,'l-a-t+-+'-f---l::;;;,'/"---t---t,-..W."1,Uop.!!J''"LU,,l ""fl!'lf-l'.!,1,.'ltH! | |||
*IU.,1f!''.....1,il_"_"+--1-*--_--::..:-:..:i=-=--+--+---+-- 48 Ann'I Total ,, .... "' *1p1,; 111, 111. l - - , 1 .. 1" " | *IU.,1f!''.....1,il_"_"+--1-*--_--::..:-:..:i=-=--+--+---+-- 48 Ann'I Total ,, .... "' *1p1,; 111, 111. l - - , 1 .. 1" " | ||
Price Gain Return r,,,.. ...:_*.:.*....\,,...--:!1£,.1;..,,,;:-:;i,~*'---hll!J*Whi!.!IIJJ.,l::..'' ~**1-*'_' _'...:"I...:'1-''_- " t - - + - - + - - l - - + - - l - - + - - + - - - + - - - I - 32 High 75 (+10%) _6 :%%,, "'**--<* ., .. *, ''-,"".i,', | Price Gain Return r,,,.. ...:_*.:.*....\,,...--:!1£,.1;..,,,;:-:;i,~*'---hll!J*Whi!.!IIJJ.,l::..'' ~**1-*'_' _'...:"I...:'1-''_- " t - - + - - + - - l - - + - - l - - + - - + - - - + - - - I - 32 High 75 (+10%) _6 :%%,, "'**--<* ., .. *, ''-,"".i,', | ||
Low 55 Insider Decisions | Low 55 Insider Decisions | ||
(-20%) 1 | (-20%) 1 | ||
] | ] | ||
......... 0 24 20 M J J A S O N D J 1----t---;t---+-+-t---+--t---+--''....:''F"'-''':....,,'"-'P'._,,-.,.-"'"'"!--*'_"'-"1-"-'_'_F---+--t---l---+---+- 16 0 0 to Buy 000000000 I Options o 8 0 0 1 O O O 8 l---+---1,lt---+-+j-t---+--+---+--l----1---l----1---1----1---1-- --l---+---+- 12 I | |||
......... 0 | |||
24 20 M J J A S O N D J 1----t---;t---+-+-t---+--t---+--''....:''F"'-''':....,,'"-'P'._,,-.,.-"'"'"!--*'_"'-"1-"-'_'_F---+--t---l---+---+- 16 0 0 to Buy 000000000 I Options o 8 0 0 1 O O O 8 l---+---1,lt---+-+j-t---+--+---+--l----1---l----1---1----1---1-- --l---+---+- 12 I | |||
toSell 1 OOOO OO O O | toSell 1 OOOO OO O O | ||
% TOT. RETURN 2/18 ~B Institutional Decisions 2Q2017 3Q2017 4Q2017 Percent I | % TOT. RETURN 2/18 ~B Institutional Decisions 2Q2017 3Q2017 4Q2017 Percent I | ||
| Line 7,040: | Line 6,517: | ||
* 80 Price Gain Ann'I Total Return P~T~~r~~~-,-,--::: ;:: | * 80 Price Gain Ann'I Total Return P~T~~r~~~-,-,--::: ;:: | ||
.. 111 1 | .. 111 1 | ||
--r~i:ii<i;;~t;:ii11i;:;:;.l~?'Tjj' | --r~i:ii<i;;~t;:ii11i;:;:;.l~?'Tjj' 111 .. 1f;;,,~11F=,Ti,~~-:,,;.c:f:i.._;:-_~_:-:_j-----j1-f~=-=-=1=.;160 High 110 (+50%) 14% " 1 1 | ||
111 .. 1f;;,,~11F=,Ti,~~-:,,;.c:f:i.._;:-_~_:-:_j-----j1-f~=-=-=1=.;160 | |||
High 110 (+50%) 14% " 1 1 | |||
1,,,, ,, * " 1 ... ~ - 'I' 50 Low 85 {+15%) 8% ' 40 1"i"*--** * .**** *.......****** *. | 1,,,, ,, * " 1 ... ~ - 'I' 50 Low 85 {+15%) 8% ' 40 1"i"*--** * .**** *.......****** *. | ||
Insider Decisions * "*.:>; ..... | Insider Decisions * "*.:>; ..... | ||
| Line 7,091: | Line 6,564: | ||
Median: 15.0 RElATIVE PIE RATIO O93 DIV'YLDD 3.8% | Median: 15.0 RElATIVE PIE RATIO O93 DIV'YLDD 3.8% | ||
I | I | ||
*fl!1*11 TIMELINESS 4 Lowered 8/18117 High: 52.9 49.3 46.3 51.0 62.7 66.0 64.0 68.9 72.3 81.9 89.7 84.9 Target Price Range Low: 43.1 34.1 32.6 41.5 48.6 53,6 54.2 52.2 56.9 63.5 72.1 74.6 2021 2022 2023 SAFETY 1 New 7/27/90 LEGENDS 120 2 - ~:~ ~vi1i1~~!sf ~~le 100 | *fl!1*11 TIMELINESS 4 Lowered 8/18117 High: 52.9 49.3 46.3 51.0 62.7 66.0 64.0 68.9 72.3 81.9 89.7 84.9 Target Price Range Low: 43.1 34.1 32.6 41.5 48.6 53,6 54.2 52.2 56.9 63.5 72.1 74.6 2021 2022 2023 SAFETY 1 New 7/27/90 LEGENDS 120 2 - ~:~ ~vi1i1~~!sf ~~le 100 TECHNICAL Lowered 2/9/18 . , . , Relative ~rice Strength ,,. - - , ** 11 ...... - ., 80 BETA .50 (1 .00 = Market) | ||
TECHNICAL Lowered 2/9/18 . , . , Relative ~rice Strength ,,. - - , ** 11 ...... - ., 80 BETA .50 (1 .00 = Market) | |||
., illl 11111 ..... | ., illl 11111 ..... | ||
- - .... 1..* | - - .... 1..* | ||
O~~~~!/ir~a indicates recession ~ | O~~~~!/ir~a indicates recession ~ | ||
| Line 7,103: | Line 6,572: | ||
... ... -- ... 32 Low 70 Insider Decisions | ... ... -- ... 32 Low 70 Insider Decisions | ||
(-10% 2% | (-10% 2% | ||
I I | I I 24 20 AMJJASOND I I 16 toBuy 11 9 811 8 811 8 8 I l 12 Options 392000220 to Soll 0 0 0 0 1 0 ~ 0 0 Institutional Decisions I I %TOT. RETURN 1/18 t-8 I I I THIS VLARITH.' | ||
1Q2017 2Q2017 3Q2017 Percent 21 STOCK INDEX | |||
24 20 AMJJASOND I I 16 toBuy 11 9 811 8 811 8 8 I l 12 Options 392000220 to Soll 0 0 0 0 1 0 ~ 0 0 Institutional Decisions I I %TOT. RETURN 1/18 t-8 I I I THIS VLARITH.' | |||
,I to Buy 322 330 335 II. ., I. 1 yr. 11.8 17.3 I-tMil shares 3yr. 29.7 38.0 t-to Soll 336 323 322 traded 1 7 4- " ,1 ~ | ,I to Buy 322 330 335 II. ., I. 1 yr. 11.8 17.3 I-tMil shares 3yr. 29.7 38.0 t-to Soll 336 323 322 traded 1 7 4- " ,1 ~ | ||
Hld'slOOOI 197947 196270 197384 1111 ;111111111 fu111iiii 1111111111 filtl,11111111111111111 Syr. 72.1 85.6 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 © VALUE LINE PUB. LLC 1, 1-23 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 42.85 39.59 37.60 38.80 39.80 Revenues per sh 43.00 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 7.93 7.89 8.40 8.80 9.15 "Cash Flow" per sh 10.50 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 4.05 3.94 4.05 4.20 4.30 Earnings per sh A 4.75 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 2.76 2.86 2.96 Div'd Decl'd per sh e | Hld'slOOOI 197947 196270 197384 1111 ;111111111 fu111iiii 1111111111 filtl,11111111111111111 Syr. 72.1 85.6 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 © VALUE LINE PUB. LLC 1, 1-23 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 42.85 39.59 37.60 38.80 39.80 Revenues per sh 43.00 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 7.93 7.89 8.40 8.80 9.15 "Cash Flow" per sh 10.50 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 4.05 3.94 4.05 4.20 4.30 Earnings per sh A 4.75 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 2.76 2.86 2.96 Div'd Decl'd per sh e | ||
| Line 7,159: | Line 6,622: | ||
to Buy tos,11 117 3Q2D17 2Q2017 78 96 4Q2017 83 86 Percent 67 fraded hares 14 "",i-1,1-,1-111"'11-4111""*111"',,----+. | to Buy tos,11 117 3Q2D17 2Q2017 78 96 4Q2017 83 86 Percent 67 fraded hares 14 "",i-1,1-,1-111"'11-4111""*111"',,----+. | ||
21 7 ' 1111 ** *" ,,. 1 "' | 21 7 ' 1111 ** *" ,,. 1 "' | ||
~ 1 | ~ 1 | ||
.ull wl .u11u.u,.111JJ.LL111111J,J.1llwl lJ/.W111u..w.1111wllJ1J.ll l l il UIII | .ull wl .u11u.u,.111JJ.LL111111J,J.1llwl lJ/.W111u..w.1111wllJ1J.ll l l il UIII | ||
| Line 7,199: | Line 6,661: | ||
Company's earnings will advance The utility is required to file a general ANNUAL RATES Past Past Est'd '15*'17 rate case in New Mexico by July of of change (per sh) 10 Yrs. 5 yrs. | Company's earnings will advance The utility is required to file a general ANNUAL RATES Past Past Est'd '15*'17 rate case in New Mexico by July of of change (per sh) 10 Yrs. 5 yrs. | ||
* to '21-'23 slightly this year. The utility will have a Revenues 2.0% .. 2.5% full year's worth of the rate increase in 2019. EPE may file sooner; we note that "Cash Flow" 5.5% 1.0% | * to '21-'23 slightly this year. The utility will have a Revenues 2.0% .. 2.5% full year's worth of the rate increase in 2019. EPE may file sooner; we note that "Cash Flow" 5.5% 1.0% | ||
4.0% Texas that took effect in July of 2017. EPE the portion of Units 3 and 4 of a new gas-Earnings 6.5% 4.5% fired generating station that is allocated to Dividends .. 18.0% 7.0% is also benefiting from above-average cus-Book Value 7.5% 6.5% 4.0% tamer growth that stems from the healthy New Mexico is not reflected in rates. How-economy in El Paso and environs. On the ever,. the regulatory climate in New Mexi-Cal* QUARTERLY REVENUES ($ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year other hand, the weather was favorable for co is difficult (not just for EPE), so the the company in 2017, and we assume company might well wait until it is re-2015 163.8 219.5 289.7 176.9 849.9 quired to file before it puts forth its rate 2016 157.8 217.9 323.2 188.0 886.9 normal weather this year. Our 2018 earn-2017 171.3 251.8 297.5 196.2 916.8 ings estimate, which we lowered by $0.20 application. | 4.0% Texas that took effect in July of 2017. EPE the portion of Units 3 and 4 of a new gas-Earnings 6.5% 4.5% fired generating station that is allocated to Dividends .. 18.0% 7.0% is also benefiting from above-average cus-Book Value 7.5% 6.5% 4.0% tamer growth that stems from the healthy New Mexico is not reflected in rates. How-economy in El Paso and environs. On the ever,. the regulatory climate in New Mexi-Cal* QUARTERLY REVENUES ($ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year other hand, the weather was favorable for co is difficult (not just for EPE), so the the company in 2017, and we assume company might well wait until it is re-2015 163.8 219.5 289.7 176.9 849.9 quired to file before it puts forth its rate 2016 157.8 217.9 323.2 188.0 886.9 normal weather this year. Our 2018 earn-2017 171.3 251.8 297.5 196.2 916.8 ings estimate, which we lowered by $0.20 application. | ||
2018 170 255 305 195 925 a share, is within management's guidance We expect a dividend hike at the 2019 175 260 315 200 950 of $2.30-$2.65 a share. Next year, the utili- board meeting in May. This has been EARNINGS PER SHARE A ty will benefit from rate relief in Texas the pattern since the directors initiated a Cal* Full common dividend several years ago. We endar Mar.31 Jun.30 Sep.JO Dec.31 Year through transmission and distribution reg-ulatory mechanisms. However . . . estimate an increase of $0.10 a share 2015 .09 .52 1.40 .02 2.03 (7.5%) in the annual disbursement. EPE's 2016 d.14 .55 1.84 .14 2.39 Earnings have become less predic-2017 d.10 .89 1.47 .16 2.42 table. The company owns a 15.8% share of goal is a payout ratio in a range of 55%- | 2018 170 255 305 195 925 a share, is within management's guidance We expect a dividend hike at the 2019 175 260 315 200 950 of $2.30-$2.65 a share. Next year, the utili- board meeting in May. This has been EARNINGS PER SHARE A ty will benefit from rate relief in Texas the pattern since the directors initiated a Cal* Full common dividend several years ago. We endar Mar.31 Jun.30 Sep.JO Dec.31 Year through transmission and distribution reg-ulatory mechanisms. However . . . estimate an increase of $0.10 a share 2015 .09 .52 1.40 .02 2.03 (7.5%) in the annual disbursement. EPE's 2016 d.14 .55 1.84 .14 2.39 Earnings have become less predic-2017 d.10 .89 1.47 .16 2.42 table. The company owns a 15.8% share of goal is a payout ratio in a range of 55%- | ||
| Line 7,230: | Line 6,691: | ||
-----1-~-+-5~y_r.~=44_.=s~=s_a._a......,_ | -----1-~-+-5~y_r.~=44_.=s~=s_a._a......,_ | ||
24.3 ;:: | 24.3 ;:: | ||
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 @VALUELINE PUB. LLC1* 1-23 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 35.37 36.43 37.81 38.35 40.20 Revenues per sh 46.75 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 10.35 10.43 11.03 11.45 12.05 "Cash Flow" per sh 14.25 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 4.15 3.94 4.51 4.55 4.70 Earnings per sh A 5.50 | 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 @VALUELINE PUB. LLC1* 1-23 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 35.37 36.43 37.81 38.35 40.20 Revenues per sh 46.75 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 10.35 10.43 11.03 11.45 12.05 "Cash Flow" per sh 14.25 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 4.15 3.94 4.51 4.55 4.70 Earnings per sh A 5.50 | ||
** *- .80 1.02 1.10 1.18 1.23 1.25 1.27 1.29 1.31 1.37 1.48 1.73 1.98 2.23 2.45 2.57 Div'd Decl'd per sh e | ** *- .80 1.02 1.10 1.18 1.23 1.25 1.27 1.29 1.31 1.37 1.48 1.73 1.98 2.23 2.45 2.57 Div'd Decl'd per sh e | ||
| Line 7,258: | Line 6,718: | ||
Dividends 6.0% 9.0% 8.0% of the wildfires has not yet been deter- approve such spending in previous rate Book Value 4.5% 3.0% 3.5% mined, but SCE has already been hit with cases. An order is expected by yearend. | Dividends 6.0% 9.0% 8.0% of the wildfires has not yet been deter- approve such spending in previous rate Book Value 4.5% 3.0% 3.5% mined, but SCE has already been hit with cases. An order is expected by yearend. | ||
t--C-al---.--Q-UA_R_T-ER-LY_R_EV_E_N-UE-S-($_m_il_l.)-,-F-ul-il some lawsuits alleging that its power lines Tax reform is slightly negative for the endar Mar.31 Jun.30 Sep.30 Dec.31 Year were at fault. (It has $1 billion in liability company. Edison International has about 1-2-0-15-+-2-1-- | t--C-al---.--Q-UA_R_T-ER-LY_R_EV_E_N-UE-S-($_m_il_l.)-,-F-ul-il some lawsuits alleging that its power lines Tax reform is slightly negative for the endar Mar.31 Jun.30 Sep.30 Dec.31 Year were at fault. (It has $1 billion in liability company. Edison International has about 1-2-0-15-+-2-1-- | ||
52 | 52 2908 3763 | ||
2908 3763 | |||
- - -+-.ccc.:..'--I 234 1 11 524 insurance.) Under California's inverse con- $1.75 billion of long-term debt at the 2016 2440 2777 3767 2885 11869 demnation law, a utility can be held liable parent level, so corporate interest and 2017 2463 2965 3672 3220 12320 if its power lines contributed to the wild- other expenses will have a lower tax 2018 2500 3000 3800 3200 12500 fires, even if the utility followed accepted shield. This is also true for the company's 2019 2600 3150 4000 3350 13100 inspection and safety rules. If this occurs, nonutility energy-services subsidiary, t--C-al---+---EA-R-NI-NGS-P-ER_S_H-AR_E_A---+-F-ul-il there is no assurance that the utility will Edison Energy, which is still in its start-endar Mar.31 Jun.30 Sep.30 Dec.31 Year be allowed to pass these costs through to up phase and is in the red. Management 1-2-0-15--t-.-91--1-.1-5--1'-.- --_---+......:..:. :;_c....i 15 94 4 15 ratepayers. So, the company is pursuing a estimates that the corporate and non-2016 .85 .86 1.27 .96 3.94 three-pronged strategy to address this utility drag on earnings will amount to 2017 1.11 .85 1.43 1.12 4.51 risk, seeking legislative, regulatory, and $0.25-$0.30 a share this year. Note that 2018 1.10 .90 1.45 1.10 4.55 judicial solutions to this problem. the company is not providing earnings 2019 1.15 .90 1.50 1.15 4.70 SCE is awaiting an order on its gener- guidance as long as the general rate case 1--C-aJ-.-+--Q-UA-R-TE-R-LY_D_IV-ID-EN_D_S_PA-ID_e_.__,_F-ul-,I al rate case. The utility has revised its is pending. | - - -+-.ccc.:..'--I 234 1 11 524 insurance.) Under California's inverse con- $1.75 billion of long-term debt at the 2016 2440 2777 3767 2885 11869 demnation law, a utility can be held liable parent level, so corporate interest and 2017 2463 2965 3672 3220 12320 if its power lines contributed to the wild- other expenses will have a lower tax 2018 2500 3000 3800 3200 12500 fires, even if the utility followed accepted shield. This is also true for the company's 2019 2600 3150 4000 3350 13100 inspection and safety rules. If this occurs, nonutility energy-services subsidiary, t--C-al---+---EA-R-NI-NGS-P-ER_S_H-AR_E_A---+-F-ul-il there is no assurance that the utility will Edison Energy, which is still in its start-endar Mar.31 Jun.30 Sep.30 Dec.31 Year be allowed to pass these costs through to up phase and is in the red. Management 1-2-0-15--t-.-91--1-.1-5--1'-.- --_---+......:..:. :;_c....i 15 94 4 15 ratepayers. So, the company is pursuing a estimates that the corporate and non-2016 .85 .86 1.27 .96 3.94 three-pronged strategy to address this utility drag on earnings will amount to 2017 1.11 .85 1.43 1.12 4.51 risk, seeking legislative, regulatory, and $0.25-$0.30 a share this year. Note that 2018 1.10 .90 1.45 1.10 4.55 judicial solutions to this problem. the company is not providing earnings 2019 1.15 .90 1.50 1.15 4.70 SCE is awaiting an order on its gener- guidance as long as the general rate case 1--C-aJ-.-+--Q-UA-R-TE-R-LY_D_IV-ID-EN_D_S_PA-ID_e_.__,_F-ul-,I al rate case. The utility has revised its is pending. | ||
endar Mar.31 Jun.30 Sec.30 Dec.31 Year request to pass through to customers the The wildfire risks hurt the stock last 1- - - -~_= ~~. = = ~~_~ ~ ~~_- - --.4-, benefits of federal tax reform. SCE is ask- year, and the price has risen .just 2014 355 355 355 355 1 2 201S .41 75 .4175 .41 75 .4175 1.67 ing for a reduction of $106 million in 2018 slightly in 2018. The dividend yield and 2016 .48 .48 .48 .48 1.92 and increases of $431 million and $503 3- to 5-year total return potential are 2017 .5425 .5425 .5425 .5425 2.17 million at the start of 2019 and 2020, res- above average for this industry. | endar Mar.31 Jun.30 Sec.30 Dec.31 Year request to pass through to customers the The wildfire risks hurt the stock last 1- - - -~_= ~~. = = ~~_~ ~ ~~_- - --.4-, benefits of federal tax reform. SCE is ask- year, and the price has risen .just 2014 355 355 355 355 1 2 201S .41 75 .4175 .41 75 .4175 1.67 ing for a reduction of $106 million in 2018 slightly in 2018. The dividend yield and 2016 .48 .48 .48 .48 1.92 and increases of $431 million and $503 3- to 5-year total return potential are 2017 .5425 .5425 .5425 .5425 2.17 million at the start of 2019 and 2020, res- above average for this industry. | ||
| Line 7,277: | Line 6,735: | ||
IRECENT 88 84 IP/E 211 (Trailing:21.1) RELATIVE 112 DIV'D 2701.~ 14.---101--P/E_RAT~IO_,---,--L_YLD~-'~/O.JIIUW.;ll~--1 TIMELINESS 2 Raised 1 22117 21 High: 39.2 35. 1 I 32.8 37.8 42.7 45.7 54.7 | IRECENT 88 84 IP/E 211 (Trailing:21.1) RELATIVE 112 DIV'D 2701.~ 14.---101--P/E_RAT~IO_,---,--L_YLD~-'~/O.JIIUW.;ll~--1 TIMELINESS 2 Raised 1 22117 21 High: 39.2 35. 1 I 32.8 37.8 42.7 45.7 54.7 | ||
* 70.1 70.5 83.4 100.0 91.4 Target Price Range Low: 30.1 21.9 20.9 30.0 33.9 38.2 43.1 50.2 55.4 65.0 77.5 79.6 2021 2022 2023 SAFETY 2 Raised 8/2/13 _L_EG~.~r:Dividends p sh f--t-----l--+~---1--+----+--+----+--+----+--+----+--+---+ 120 TECHNICAL 3 Lowered2/23/18 .... i~i~f~eb~r/gleg\~ln~~e t---+-----1--+----+--+---+--+---+-~,+---+--+---+--+-.- | * 70.1 70.5 83.4 100.0 91.4 Target Price Range Low: 30.1 21.9 20.9 30.0 33.9 38.2 43.1 50.2 55.4 65.0 77.5 79.6 2021 2022 2023 SAFETY 2 Raised 8/2/13 _L_EG~.~r:Dividends p sh f--t-----l--+~---1--+----+--+----+--+----+--+----+--+---+ 120 TECHNICAL 3 Lowered2/23/18 .... i~i~f~eb~r/gleg\~ln~~e t---+-----1--+----+--+---+--+---+-~,+---+--+---+--+-.- | ||
1111 ... | 1111 ... | ||
****** ,11 | ****** ,11 | ||
.... * *-.-.+-. ~~O t-B_E_TA2ii:.7ff0~(1.POOR=0:M]ark~e:Tt)fmiS-1-01~~~~~~~':!!~'.!,Yi,:!!c~a!!_.!ii!!!nc/,1jE.ic~ate~s.f!re~ce~ss~io'!!_.,nf--t-----1--+--=----l--+--='fllr.'.,,.,ll,,.:.C.---+---'-'l-'--'.__-d,---+----+-~+----+ 11111 | .... * *-.-.+-. ~~O t-B_E_TA2ii:.7ff0~(1.POOR=0:M]ark~e:Tt)fmiS-1-01~~~~~~~':!!~'.!,Yi,:!!c~a!!_.!ii!!!nc/,1jE.ic~ate~s.f!re~ce~ss~io'!!_.,nf--t-----1--+--=----l--+--='fllr.'.,,.,ll,,.:.C.---+---'-'l-'--'.__-d,---+----+-~+----+ 11111 | ||
, - - -- 64 I/- | , - - -- 64 I/- | ||
| Line 7,345: | Line 6,800: | ||
% TOT. RETURN 2118 THIS STOCK VLARITH.' | % TOT. RETURN 2118 THIS STOCK VLARITH.' | ||
INDEX | INDEX | ||
~7.5 | ~7.5 to Buy 198 194 190 shares 16 ' I " I I 1 yr. 1.0 10.1 ~ | ||
to Buy 198 194 190 shares 16 ' I " I I 1 yr. 1.0 10.1 ~ | |||
tos,11 188 187 165 traded 8 I ,. 111 ilmhlll!lhl*lo.l " II I "' ,, I ,, II 3yr. 34.3 24.2 - | tos,11 188 187 165 traded 8 I ,. 111 ilmhlll!lhl*lo.l " II I "' ,, I ,, II 3yr. 34.3 24.2 - | ||
Hld's(DODl 179256 182717 166325 lllllllllllll llllllllWIIIIIIII 11111111111111111111 11111111111 1111111111111111111111111111111111 1111111111 II Syr. 92.2 76.2 Alliant Energy, formerly called Interstate En- 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 @VALUELINEPUB.LLC, 1-23 ergy Corporation, was formed on April 21, 16.67 15.51 15.40 16.51 13.94 14.77 15.10 14.34 14.58 14.62 15.30 15.55 Revenues per sh 17.75 1998 through the merger of WPL Holdings, 2.28 2.10 2.60 2.75 2.95 3.34 3.44 3.45 3.45 3.97 4.25 4.45 "Cash Flow" per sh 5.00 IES Industries, and Interstate Power. WPL 1.27 .95 1.38 1.38 1.53 1.65 1.74 1.69 1.65 1.99 2.10 2.25 Earnings per sh A 2.60 stockholders received one share of Inter- .70 .75 .79 .85 .90 .94 1.02 1.10 1.18 1.26 1.34 1.42 Div'd Decl'd per sh e | Hld's(DODl 179256 182717 166325 lllllllllllll llllllllWIIIIIIII 11111111111111111111 11111111111 1111111111111111111111111111111111 1111111111 II Syr. 92.2 76.2 Alliant Energy, formerly called Interstate En- 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 @VALUELINEPUB.LLC, 1-23 ergy Corporation, was formed on April 21, 16.67 15.51 15.40 16.51 13.94 14.77 15.10 14.34 14.58 14.62 15.30 15.55 Revenues per sh 17.75 1998 through the merger of WPL Holdings, 2.28 2.10 2.60 2.75 2.95 3.34 3.44 3.45 3.45 3.97 4.25 4.45 "Cash Flow" per sh 5.00 IES Industries, and Interstate Power. WPL 1.27 .95 1.38 1.38 1.53 1.65 1.74 1.69 1.65 1.99 2.10 2.25 Earnings per sh A 2.60 stockholders received one share of Inter- .70 .75 .79 .85 .90 .94 1.02 1.10 1.18 1.26 1.34 1.42 Div'd Decl'd per sh e | ||
| Line 7,375: | Line 6,828: | ||
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRD_RS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, intemal_use. No part of it may be reproduced, resold, stored or transmitted in any pnnted, electronic or other form, or used for generating or marketing an printed or electronic publication, service or product. | THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRD_RS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, intemal_use. No part of it may be reproduced, resold, stored or transmitted in any pnnted, electronic or other form, or used for generating or marketing an printed or electronic publication, service or product. | ||
IllEammgs Predtctabtlily I Ill~,.~, I ' * | IllEammgs Predtctabtlily I Ill~,.~, I ' * | ||
* 11 1 90 | * 11 1 90 | ||
| Line 7,385: | Line 6,837: | ||
2021*23 PROJECTIONS , , I~ .. ,..Jff..., 11,*u 1'h" 11 111 .,,.,~.,: r1-ll... ----- -----* 48 Price Gain Ann'I Total Return ........... , | 2021*23 PROJECTIONS , , I~ .. ,..Jff..., 11,*u 1'h" 11 111 .,,.,~.,: r1-ll... ----- -----* 48 Price Gain Ann'I Total Return ........... , | ||
I ] / | I ] / | ||
__./ .. 1 ., 1, 1.,,, 1, 1* 111111 | __./ .. 1 ., 1, 1.,,, 1, 1* 111111 High 15 (+35%1 11% /"..t**.'-**"c._**- .t-"1*1r,::i.,,,:t1_:---:- .-t=.+/-1 =Ri?.7::7f.'ir"'flJJ-F"--4---t---t-- 1 1 1---t--1 1---t---t---t---t----t-32 1e:.;1l_"'_"t-'_ _t---+---ll--+--t-:---+--t--+---11--+---l--+ 24 1 | ||
High 15 (+35%1 11% /"..t**.'-**"c._**- .t-"1*1r,::i.,,,:t1_:---:- .-t=.+/-1 =Ri?.7::7f.'ir"'flJJ-F"--4---t---t-- 1 1 1---t--1 1---t---t---t---t----t-32 1e:.;1l_"'_"t-'_ _t---+---ll--+--t-:---+--t--+---11--+---l--+ 24 1 | |||
~L~ow~~5~0__,.J;l*:..'.1~o*~x.L~2~%~1-'='-t,,-;:-'-: *1:::?. . . . ."'1Jl,,-1;1ff~...C'f''-'' | ~L~ow~~5~0__,.J;l*:..'.1~o*~x.L~2~%~1-'='-t,,-;:-'-: *1:::?. . . . ."'1Jl,,-1;1ff~...C'f''-'' | ||
Insider Decisions * -. ... '11111 20 J J A SO N D J F 1 - - - - + - - | Insider Decisions * -. ... '11111 20 J J A SO N D J F 1 - - - - + - - | ||
| Line 7,447: | Line 6,897: | ||
..... ii...- 11 .. 11 | ..... ii...- 11 .. 11 | ||
~ ** ****111 (1t!.* ***** *.......... ****** | ~ ** ****111 (1t!.* ***** *.......... ****** | ||
to Buy O O O O O O O O O i,...*:::'=-=i---=:*:,, ..'-"''l-1--"-1-+:.i..+'--l---+---l---+---l---+'~~-1.-.-.,~ | to Buy O O O O O O O O O i,...*:::'=-=i---=:*:,, ..'-"''l-1--"-1-+:.i..+'--l---+---l---+---l---+'~~-1.-.-.,~ | ||
Options 000000000 I l ,;,-..,,,* ..,k..~.~.-..-l---+---l---+---1-----1-10 to Sell o o o 1 o o 2 o O l---+-------''1----+----'-,-+----+--+----+---+----+---+----+---+'---+-----1 % TOT. RETURN 2118 - 7.5 Institutional Decisions I THIS vLARITll' | Options 000000000 I l ,;,-..,,,* ..,k..~.~.-..-l---+---l---+---1-----1-10 to Sell o o o 1 o o 2 o O l---+-------''1----+----'-,-+----+--+----+---+----+---+----+---+'---+-----1 % TOT. RETURN 2118 - 7.5 Institutional Decisions I THIS vLARITll' | ||
.to Buy to Sell 2Q2D17 3Q2017 4Q2D17 159 202 Hld's(OOD 145860 145781 124353 151 155 155 138 Percent shares traded 18 1 12Jlimitltffiffi 6 | .to Buy to Sell 2Q2D17 3Q2017 4Q2D17 159 202 Hld's(OOD 145860 145781 124353 151 155 155 138 Percent shares traded 18 1 12Jlimitltffiffi 6 | ||
1 I 1,,111lllllll"h-l"ffit11.clllk4Hn h-.J!Hil l !Hh111"11ftl;:ti":,.Hl Ullllillll """"' 111111111 Ulllllllll 111111ij111 | 1 I 1,,111lllllll"h-l"ffit11.clllk4Hn h-.J!Hil l !Hh111"11ftl;:ti":,.Hl Ullllillll """"' 111111111 Ulllllllll 111111ij111 II tl " ;;:,rn'--'*--1--..__j 1 | ||
II tl " ;;:,rn'--'*--1--..__j 1 | |||
3 yr. | 3 yr. | ||
yr. | yr. | ||
| Line 7,555: | Line 7,001: | ||
, . , . Relative rice Strength 80 BETA .65 (1.00 = Market) 60 O~~~~:/ir~a indicates recession 50 | , . , . Relative rice Strength 80 BETA .65 (1.00 = Market) 60 O~~~~:/ir~a indicates recession 50 | ||
- -- ,.,-.r,,,, | - -- ,.,-.r,,,, | ||
,111,111*1 2021-23 PROJECTIONS 40 Ann'I Total I I I **--- | |||
,111,111*1 2021-23 PROJECTIONS | |||
40 Ann'I Total I I I **--- | |||
_u.or11111l11111** | _u.or11111l11111** | ||
Price Gain Return / *, | Price Gain Return / *, | ||
| Line 7,570: | Line 7,012: | ||
V I I I I""* *.......... ......***** ....******* ****...... ********... ........... *********. ........... 15 10 Options 10 O 010 O 0 0 0 5 i ! | V I I I I""* *.......... ......***** ....******* ****...... ********... ........... *********. ........... 15 10 Options 10 O 010 O 0 0 0 5 i ! | ||
toSell O O OO0 0 0 0 1 ~7.5 | toSell O O OO0 0 0 0 1 ~7.5 | ||
% TOT. RETURN 3/18 Institutional Decisions 2Q2017 3Q2017 4Q2017 Percent 121 I I I) ., I. 1, I THIS STOCK VLARITH.' | % TOT. RETURN 3/18 Institutional Decisions 2Q2017 3Q2017 4Q2017 Percent 121 I I I) ., I. 1, I THIS STOCK VLARITH.' | ||
INDEX | INDEX 1 yr. -6.0 9.7 to Buy to Sell 147 112 122 118 136 shares 91 traded 14 I II | ||
1 yr. -6.0 9.7 to Buy to Sell 147 112 122 118 136 shares 91 traded 14 I II | |||
""II@ 1~~1!1~111 ~l!ltl~I I ~~l!l~l l ~~ij~I 1111 Ill 3yr. 19.9 24.3 | ""II@ 1~~1!1~111 ~l!ltl~I I ~~l!l~l l ~~ij~I 1111 Ill 3yr. 19.9 24.3 | ||
~ | ~ | ||
7 5 yr. 55.5 68.8 | 7 5 yr. 55.5 68.8 | ||
~ | ~ | ||
| Line 7,635: | Line 7,073: | ||
Insider Decisions J J A s O N D J F ****-i----r:-*** 1 L"-;_'"...-,..""r'"'r::~lfii...--:fl..,.....,.y.''.:... | Insider Decisions J J A s O N D J F ****-i----r:-*** 1 L"-;_'"...-,..""r'"'r::~lfii...--:fl..,.....,.y.''.:... | ||
I .... *....*****. ...... ... ***. .... | I .... *....*****. ...... ... ***. .... | ||
o o ---1-----;i---1--;-----t--+----- +--+--*-**=**-*=*~*~**--+*_***=*c..**-***--+*--+----+-""---+--+-----+-- +----+-10 | o o ---1-----;i---1--;-----t--+----- +--+--*-**=**-*=*~*~**--+*_***=*c..**-***--+*--+----+-""---+--+-----+-- +----+-10 to Buy OOO1 OOO Options o o O O O O O O12 I l - 7.5 to Sell OO 1 o o 1 1 o o Institutional Decisions 1* I JI % TOT. RETURN 3/18 I I v~::::,* | ||
to Buy OOO1 OOO Options o o O O O O O O12 I l - 7.5 to Sell OO 1 o o 1 1 o o Institutional Decisions 1* I JI % TOT. RETURN 3/18 I I v~::::,* | |||
:~:~fi 2Q2017 | :~:~fi 2Q2017 | ||
~~~ | ~~~ | ||
| Line 7,648: | Line 7,084: | ||
llfftttttlttltn * ' irlrth;r I. | llfftttttlttltn * ' irlrth;r I. | ||
11 | 11 | ||
[l]]Ill]]I I " | [l]]Ill]]I I " | ||
I | I I lht\ttttt ltttttttttmtrtt 111llitltt IIIIIIllII IllIIIIIIllJilI II | ||
I lht\ttttt ltttttttttmtrtt 111llitltt IIIIIIllII IllIIIIIIllJilI II | |||
* 1 yr. | * 1 yr. | ||
~ ~;: | ~ ~;: | ||
| Line 7,716: | Line 7,147: | ||
'""~ | '""~ | ||
I" ro" """ | I" ro" """ | ||
This capital spending will expand the utilities' rate base, and thus, boost their earning power. The utility 30 | This capital spending will expand the utilities' rate base, and thus, boost their earning power. The utility 30 | ||
* subsidiaries of American Electric Power, CMS Energy, and. DTE Energy will have frequent rate cases to earn a return on its capital expenditures. Companies recover their transmission investment through forward-looking 15 2011 2012 2013 2014 2015 2016 2017 formula rate plans. Entergy and CenterPoint Energy Index: June, 1967 = 100 | * subsidiaries of American Electric Power, CMS Energy, and. DTE Energy will have frequent rate cases to earn a return on its capital expenditures. Companies recover their transmission investment through forward-looking 15 2011 2012 2013 2014 2015 2016 2017 formula rate plans. Entergy and CenterPoint Energy Index: June, 1967 = 100 | ||
| Line 7,722: | Line 7,152: | ||
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRQRS OR OMISSIONS HEREIN. This publication is strict~ for subscribers own, non-commercial, imernal use. No part To subscribe call 1-800-VALUELINE of it may be reproduced, resold, stored or transmitted in any printed, electronic or olher fonn, or u_sed for generating or marketing any printed or electronic publication, service or product | THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRQRS OR OMISSIONS HEREIN. This publication is strict~ for subscribers own, non-commercial, imernal use. No part To subscribe call 1-800-VALUELINE of it may be reproduced, resold, stored or transmitted in any printed, electronic or olher fonn, or u_sed for generating or marketing any printed or electronic publication, service or product | ||
18-WSEE-328-RTS | 18-WSEE-328-RTS March 16, 2018 ELECTRIC UTILITY (CENTRAL) INDUSTRY 901 All of the major electric utilities located in the INDUSTRY TIMELINESS: 13 (of 97) central region of the United States are reviewed in this Issue; eastern electrics, in Issue 1; and the than they are today. However, the decline in profitability remaining utilities, in Issue 11. of these assets has induced several companies to get out of this business. Ameren discontinued its nonregulated We discuss the new federal tax law's effects on operations in 2013. American Electric Power has all but companies in the Electric Utility Industry. completed the transition from a hybrid company to a regulated entity. Entergy is also exiting almost all of its Some companies in this Industry are making a nonregulated activities, although this process will not be transition from a hybrid (utility and nonutility) completed until 2022. This will reduce the business risk company to an entirely regulated entity. that these companies face. Not every company is ceasing its nonutility operations. DTE Energy is retaining them, Mergers and acquisitions are an ongoing theme as they have less risk than nonregulated power genera-in this industry. tion and account for about 20% of corporate profits. | ||
March 16, 2018 ELECTRIC UTILITY (CENTRAL) INDUSTRY 901 All of the major electric utilities located in the INDUSTRY TIMELINESS: 13 (of 97) central region of the United States are reviewed in this Issue; eastern electrics, in Issue 1; and the than they are today. However, the decline in profitability remaining utilities, in Issue 11. of these assets has induced several companies to get out of this business. Ameren discontinued its nonregulated We discuss the new federal tax law's effects on operations in 2013. American Electric Power has all but companies in the Electric Utility Industry. completed the transition from a hybrid company to a regulated entity. Entergy is also exiting almost all of its Some companies in this Industry are making a nonregulated activities, although this process will not be transition from a hybrid (utility and nonutility) completed until 2022. This will reduce the business risk company to an entirely regulated entity. that these companies face. Not every company is ceasing its nonutility operations. DTE Energy is retaining them, Mergers and acquisitions are an ongoing theme as they have less risk than nonregulated power genera-in this industry. tion and account for about 20% of corporate profits. | |||
lkctren also has some nonutility operations. | lkctren also has some nonutility operations. | ||
Following a stellar showing in 2017, the prices of most of the stocks in this industry have declined Mergers And Acquisitions so far in 2018. Still, the group isn't cheap. | Following a stellar showing in 2017, the prices of most of the stocks in this industry have declined Mergers And Acquisitions so far in 2018. Still, the group isn't cheap. | ||
| Line 7,735: | Line 7,163: | ||
Other companies, such as WEC Energy Group, do not 75 'J' | Other companies, such as WEC Energy Group, do not 75 'J' | ||
~ '-/ | ~ '-/ | ||
need to sell common stock. | need to sell common stock. | ||
From Partly Regulated To Entirely Regulated | From Partly Regulated To Entirely Regulated | ||
* '60 45 | * '60 45 Some companies in the Electric Utility Industry are 30 (or were) hybrids. That is, they have nonregulated operations in addition to their regulated utilities. Most notably, several companies own nonregulated generat-ing assets. This was attractive a decade ago, when 15 2012 2013 2014 2015 2016 2017 2018 natural gas (and thus, power) prices were much higher Index: June, 1967 = 100 | ||
Some companies in the Electric Utility Industry are 30 (or were) hybrids. That is, they have nonregulated operations in addition to their regulated utilities. Most notably, several companies own nonregulated generat-ing assets. This was attractive a decade ago, when 15 2012 2013 2014 2015 2016 2017 2018 natural gas (and thus, power) prices were much higher Index: June, 1967 = 100 | |||
© 2019 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wihout warranties of any kind. | © 2019 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wihout warranties of any kind. | ||
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strict~ for subscriber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of it may be reproduced, resold, stored or transmitted in any printed, electroruc or other form, or usad for generating or marketing any printed or electronic publication, sarvice or product. | THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strict~ for subscriber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of it may be reproduced, resold, stored or transmitted in any printed, electroruc or other form, or usad for generating or marketing any printed or electronic publication, sarvice or product. | ||
18-WSEE-328-RTS | 18-WSEE-328-RTS February 16, 2018 ELECTRIC UTILITY (EAST) INDUSTRY 137 All of the major electric utilities located* in the INDUSTRY TIMELINESS: 88 (of 97) eastern region of the United States are reviewed in this Issue; western electrics, in Issue 11; and the will be a bit less lucrative than it would have been had it remaining ~tilities, in Issue 5. been completed on time and on budget, though, and the utility is still assuming construction risk. By contrast, We discuss how tax reform will affect companies SCE&G canceled its project, and the state legislature in the Electric Utility Industry. does not want the utility to continue to collect money from customers for the unsuccessful project. (The com-Several companies covered .in Issue 1 have in- pany believes the state's Base Load Review Act allows it volvement with nuclear power. Two have worries to continue collecting these monies.) Dominion Energy stemming from nuclear construction, and a few agreed to take over SCANA, as long as there is no have nonregulated assets that are threatened by unfavorable regulatory or legislative changes. With the unfavorable market conditions. price of SCANA stock well below the value of Dominion Energjs offer, the market is skeptical that the deal will Most electric utility stocks have retreated in be completed. | ||
February 16, 2018 ELECTRIC UTILITY (EAST) INDUSTRY 137 All of the major electric utilities located* in the INDUSTRY TIMELINESS: 88 (of 97) eastern region of the United States are reviewed in this Issue; western electrics, in Issue 11; and the will be a bit less lucrative than it would have been had it remaining ~tilities, in Issue 5. been completed on time and on budget, though, and the utility is still assuming construction risk. By contrast, We discuss how tax reform will affect companies SCE&G canceled its project, and the state legislature in the Electric Utility Industry. does not want the utility to continue to collect money from customers for the unsuccessful project. (The com-Several companies covered .in Issue 1 have in- pany believes the state's Base Load Review Act allows it volvement with nuclear power. Two have worries to continue collecting these monies.) Dominion Energy stemming from nuclear construction, and a few agreed to take over SCANA, as long as there is no have nonregulated assets that are threatened by unfavorable regulatory or legislative changes. With the unfavorable market conditions. price of SCANA stock well below the value of Dominion Energjs offer, the market is skeptical that the deal will Most electric utility stocks have retreated in be completed. | |||
price so far in 2018. However, they are still expen- Other companies reviewed in Issue 1 have a different sive, by historical standards. concern: the lack of profitability of their nonregulated nuclear plants. A combination of low gas prices, subsi-dized renewable energy, and weak demand for power has The New Federal Tax Law hurt these assets. Utilities believe current market prices A new federal tax law took effect at the start of 2018. don't recognize the benefits of nuclear generation (fuel For regulated utilities, it is highly likely that all of the diversity and no carbon emissions). So, some companies benefits of a lower tax rate will be passed through to . are seeking subsidies from the states in which their customers. The only questions are when, and how? nuclear units are based, similar to the "zero emissions However, although a one-for-one pass-through will not credits" that were granted by the Illinois legislature and affect reported profits, this will reduce a utility's cash the New York regulators for plants owned by Exelon. | price so far in 2018. However, they are still expen- Other companies reviewed in Issue 1 have a different sive, by historical standards. concern: the lack of profitability of their nonregulated nuclear plants. A combination of low gas prices, subsi-dized renewable energy, and weak demand for power has The New Federal Tax Law hurt these assets. Utilities believe current market prices A new federal tax law took effect at the start of 2018. don't recognize the benefits of nuclear generation (fuel For regulated utilities, it is highly likely that all of the diversity and no carbon emissions). So, some companies benefits of a lower tax rate will be passed through to . are seeking subsidies from the states in which their customers. The only questions are when, and how? nuclear units are based, similar to the "zero emissions However, although a one-for-one pass-through will not credits" that were granted by the Illinois legislature and affect reported profits, this will reduce a utility's cash the New York regulators for plants owned by Exelon. | ||
flow. That's because it will receive less cash from its However, this company still has a unit in Pennsylvania customers, but its cash outlays for taxes won't decline that is threatened with a premature closing, and its correspondingly because utilities' tax liabilities aren't facility in New Jersey will be shut in 2018, a year ahead entirely in cash. Some companies are paying no cash of schedule. Some companies are still seeking some kind taxes at all. In addition, as a trade-off for retaining full of subsidy that would allow them to keep their troubled tax deductibility for interest payments on utility issued nuclear plants open: FirstEnergy in Ohio, Public Service 0 | flow. That's because it will receive less cash from its However, this company still has a unit in Pennsylvania customers, but its cash outlays for taxes won't decline that is threatened with a premature closing, and its correspondingly because utilities' tax liabilities aren't facility in New Jersey will be shut in 2018, a year ahead entirely in cash. Some companies are paying no cash of schedule. Some companies are still seeking some kind taxes at all. In addition, as a trade-off for retaining full of subsidy that would allow them to keep their troubled tax deductibility for interest payments on utility issued nuclear plants open: FirstEnergy in Ohio, Public Service 0 | ||
| Line 7,781: | Line 7,204: | ||
Wisconsin, FERC. 150 | Wisconsin, FERC. 150 | ||
* Average: Arizona, California, Delaware, Florida, Iowa, 120 Kansas, Kentucky, Louisiana, Maine, Michigan, Minne- . | * Average: Arizona, California, Delaware, Florida, Iowa, 120 Kansas, Kentucky, Louisiana, Maine, Michigan, Minne- . | ||
90 rv~ ~ | 90 rv~ ~ | ||
sota, Mississippi, New Hampshire, New Jersey, North 75 .I'\ - - - | sota, Mississippi, New Hampshire, New Jersey, North 75 .I'\ - - - | ||
| Line 7,800: | Line 7,222: | ||
Paul E. Debbas, CPA This year might well see additional merger and acqui-sition activity. Besides the deals mentioned above, the Electric Utility proposed combination of Great Plains Energy and We- RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.) | Paul E. Debbas, CPA This year might well see additional merger and acqui-sition activity. Besides the deals mentioned above, the Electric Utility proposed combination of Great Plains Energy and We- RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.) | ||
star Energy (reviewed. in Issue 5) is expected to be 150 completed in 2018. | star Energy (reviewed. in Issue 5) is expected to be 150 completed in 2018. | ||
120 Changes in federal tax laws require a discussion. Most 90 | 120 Changes in federal tax laws require a discussion. Most 90 r V v-., I.../"-, | ||
r V v-., I.../"-, | |||
compaI).ies are still evaluating the effects of the new law, - | compaI).ies are still evaluating the effects of the new law, - | ||
and might not make any public statements about it until they release fourth-quarter earnings in February (for most companies). For the regulated utility business, 75 60 45 | and might not make any public statements about it until they release fourth-quarter earnings in February (for most companies). For the regulated utility business, 75 60 45 | ||
,,I | ,,I | ||
- """ ~ 'v whatever benefits the companies receive from lower taxes will be passed through to customers-the only real question is how, and over which time frame. However, 30 some utilities have nonutility siblings under the um-brella of their parent companies, and these should benefit from tax reform. Hawaiian Electric Industries, with its -American Savings Bank subsidiary, is an ex- 15 2011 2012 2013 2014 2015 2016 2017 ample. Another consideration is the deferred tax assets Index: June, 1967 = 1DO | - """ ~ 'v whatever benefits the companies receive from lower taxes will be passed through to customers-the only real question is how, and over which time frame. However, 30 some utilities have nonutility siblings under the um-brella of their parent companies, and these should benefit from tax reform. Hawaiian Electric Industries, with its -American Savings Bank subsidiary, is an ex- 15 2011 2012 2013 2014 2015 2016 2017 ample. Another consideration is the deferred tax assets Index: June, 1967 = 1DO | ||
© 2018 Value Lina, Inc. All rights reserved. Factual malenal is obtained from sources believed lo be reliable and is provided w!hout warranties ol any kind. | © 2018 Value Lina, Inc. All rights reserved. Factual malenal is obtained from sources believed lo be reliable and is provided w!hout warranties ol any kind. | ||
| Line 7,816: | Line 7,234: | ||
I TIMELINESS - Suspended 6/10/16 High: 28.6 25.9 22.3 25.9 29.0 33.0 35.0 43.2 44.0 57.5 57.3 53.3 Target Price Range Low: 22.8 16.0 14.9 20.6 22.6 26.8 28.6 31.7 33.9 40.0 49.2 47.1 2021 2022 2023 SAFETY 2 Raised 4/1105 LEGENDS 120 TECHNICAL - Suspended 6/10/16 - ~ii~:d ~vi1;t~~!sr ~~ta 100 | I TIMELINESS - Suspended 6/10/16 High: 28.6 25.9 22.3 25.9 29.0 33.0 35.0 43.2 44.0 57.5 57.3 53.3 Target Price Range Low: 22.8 16.0 14.9 20.6 22.6 26.8 28.6 31.7 33.9 40.0 49.2 47.1 2021 2022 2023 SAFETY 2 Raised 4/1105 LEGENDS 120 TECHNICAL - Suspended 6/10/16 - ~ii~:d ~vi1;t~~!sr ~~ta 100 | ||
, , , , Relative ~rice Strength 80 BETA .70 (1.00 = Marl<et) | , , , , Relative ~rice Strength 80 BETA .70 (1.00 = Marl<et) | ||
O~~~~!/i!a indicates rec~ssion -...... *-*-** 64 2021-23 PROJECTIONS Price Gain Ann'I Total Return | O~~~~!/i!a indicates rec~ssion -...... *-*-** 64 2021-23 PROJECTIONS Price Gain Ann'I Total Return I | ||
I | |||
I __/ | I __/ | ||
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11 I11,,,111 1111 | 11 I11,,,111 1111 | ||
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| Line 7,832: | Line 7,246: | ||
..~" 11(11* "* I 11**111 ' ,11 1 *1111' 24 Insider Decisions | ..~" 11(11* "* I 11**111 ' ,11 1 *1111' 24 Insider Decisions | ||
.. **-~ ... 20 | .. **-~ ... 20 | ||
-; ' .11 11,,11 MJJASONDJ 16 lo Buy 0 0 0 0 0 0 0 0 0 I 1 **-** 12 Options 0 0 6 0 0 0 0 016 I l lo Soll 0 0 0 4 0 0 5 0 0 | |||
-; ' .11 11,,11 MJJASONDJ 16 lo Buy 0 0 0 0 0 0 0 0 0 I 1 **-** 12 Options 0 0 6 0 0 0 0 016 I l | |||
lo Soll 0 0 0 4 0 0 5 0 0 | |||
% TOT. RETURN 2/18 .... 8 Institutional Decisions 111 I j I THIS VLARITH." | % TOT. RETURN 2/18 .... 8 Institutional Decisions 111 I j I THIS VLARITH." | ||
2Ql017 3Ql017 402017 Percent 2 | 2Ql017 3Ql017 402017 Percent 2 | ||
) STOCK INDEX | ) STOCK INDEX to Buy 130 164 141 shares I I ,11 1 yr. -7.0 10.1 | ||
to Buy 130 164 141 shares I I ,11 1 yr. -7.0 10.1 | |||
,ffiff 3yr. 38.3 24.2 lo Soll 201 Hld's!DOO 118673 118474 107206 146 2002 2003 2004 2005 2006 2007 2008 2009 130 traded 1:. . . | ,ffiff 3yr. 38.3 24.2 lo Soll 201 Hld's!DOO 118673 118474 107206 146 2002 2003 2004 2005 2006 2007 2008 2009 130 traded 1:. . . | ||
1Mtt11111 2011 2012 2013 11.11 1111111111 "I | 1Mtt11111 2011 2012 2013 11.11 1111111111 "I | ||
Revision as of 09:58, 2 February 2020
| ML19106A335 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 04/10/2019 |
| From: | Reasoner C Wolf Creek |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| WM 19-0008 | |
| Download: ML19106A335 (785) | |
Text
W$LFCREEK 1 NUCLEAR OPERATING CORPORATION Cleveland Reasoner Senior Vice President and Chief Nuclear Officer April 10, 2019 WM 19-0008 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 Nuclear Regulatory Commission (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. Any licensee for a plant that is involved in a merger or an acquisition shall submit this report annually. 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 direct subsidiary of Westar Energy, Inc. and indirect subsidiary of Evergy, Inc.; Kansas City Power & Light Company (KCPL), a wholly-owned direct subsidiary of Evergy, Inc; 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 ).
The Enclosures provide the required financial information to report the status of WCNOC's decommissioning funding, and legal documentation to provide the approval of the 2017 Decommissioning Cost Analysis for WCGS. The Enclosures reflect financial estimates based on the 2017 Cost Analysis.
The NRC Project Manager was contacted regarding not meeting the required due date stated in the regulations. This issue has been captured in WCNOC's Corrective Action Process as condition report 131169. This letter contains no commitments. If you have any questions concerning this matter, please contact me at (620) 364-4000, or Ron Benham at (620) 364-4204. .
Sincerely, au~
Cleveland Reasoner COR/rlt P.O. Box 411 / Burlington, KS 66839 / Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET
WM 19-0008 Page 2 of 2
Enclosures:
Wolf Creek Nuclear Operating Corporation Decommissioning Funding Status Report as of 3/31/18 II Commission Order (Docket No. 18-WCNE-107-GIE) 111 Direct Testimony of Adam H. Gatewood (September 12, 2018)
IV Joint Motion to Approve Stipulation (Docket No. 15-WCNE-093-GIE)
V Order Approving Unanimous Settlement Agreement (Docket No. 18-KCPE-480-RTS)
VI Direct Testimony of Adam H. Gatewood (July 9, 2015)
VII Order Approving Stipulation and Agreement (Docket No. 15-WSEE-115-RTS)
VIII Order Approving Unopposed Stipulation and Agreement (15-WCNE-093-GIE)
IX Order Approving Stipulation and Agreement (File No. E0-2018-0062)
X Non-Unanimous Stipulation and Agreement (File No. E0-2018-0062)
XI Direct Testimony of Adam H. Gatewood (June 11, 2018)
XII Application of Kansas City Power & Light Company (KCPL) for Approval of the Accrual and Funding of WCGS Decommissioning Costs at Current Levels XIII Annual NRC Certification Update XIV Decommissioning Cost Analysis for the Wolf Creek Generating Station (W11-1741-001, Rev. 0) cc: S. A. Morris (NRC), w/e B. K. Singal (NRC), w/e N. H. Taylor (NRC), w/e Senior Resident Inspector (NRC), w/e
Enclosure I to WM 19-0008 Wolf Creek Nuclear Operating Corporation Decommissioning Funding Status Report as of 3/31/18 (15 pages)
Wolf Creek Nuclear Operating Corporation Decommissioning Funding Status Report as of 3/31/19 Owned by Kansas Gas & Electric (KGE), Kansas City Power and Light (KCPL) and Kansas Electric Power Cooperative *(KEPCo)
Westar Energy Great Plains Energy 10 CFR 50.751f111l Reauirement (KGE, 47% ownership) (KCPL, 47% ownership) KEPCo, 6% ownership TOTAL Notes I
- 1) NRC minimum decommissioning estimate pursuant to 10 CFR 50.75( b,) and ( c) Dollars in Millions. $242.95 $242.95 $31.02 $516.92
- 2) The amount of accumulated funds at the end of the calendar year.preceding the date of the report for items
$227.46 $244.61 $25.01 $497.07 included in 10 CFR 50.75 ( b) and ( c ). Dollars in Millions.
- 3) A schedule of the annual amounts to be collected; for Current scheduled amounts established in items in 1o CFR 50.75 ( b) and ( c ). Dollars in Millions. KCC Docket 15-WSEE-115-RTS Testimony See Attached Schedules of Gatewood.
Collection amounts for 2018/2019 have not
$151.54 been established/approved as of 3/31/2019
$87.07 $16.24 $254.85 for KGE/KEPCo, KCC Docket 18-WSEE-328-RTS.
KCPL contributions established in KCC Docket 18-KCPE-480-RTS and E0-2018-0062
- 4) The assumptions used regarding: New escalation rate approved for Kansas in (a) Rates of escalation in decommissioning costs; 2018 @ 2.91 %, new Site Specific .
Kansas 2.91% 2.91% 2.91% Methodology Approved from DECON to SAFSTOR as found in KCC Docket 18-WCNE-107-GIE.
Missouri NIA 3.16% NIA Missouri Rates established on E0-2018-062 (b) Rates of earning on decommissioning funds; Kansas earnings rates riot approved as of 3/31/19 by the KCC for KGE/KEPCo. Use rates established in KCC Docket 15-WSEE-Variable. See attached Variable. See attached Variable. See attached 115-RTS, Testimony of Gatewood.
KCPL earnings rates established on 18-KCPE-480-RTS (c) Rates of other factors used in funding projections; and -
0.00% 0.00% 0.00%
(d) Real rate of return for current period, rate reduces in .'
subsequent years; 2.69% 1.71% 3.83%
- 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 submitted report? None None None
- 7) Any material changes to trust agreements?
None None None Other information* estimated coroorate tax rate 20.00% 20.00% Non-taxable
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) . 4.923 Minimum estimate - Dec18 dollars in Millions $ 516.92 Escalation per paragraph (c}(2}
Escalation Factor = 0.65 Labor + 0.13 Energy + 0.22 Waste Burial Share 4Q '18 Reeort
,Labor 65% 2.750 1.788
' 13% 2.365 0.307 Energy Waste Burial 22% 12.853 2.828 TOTAL ESCALATION FACTOR 4.923 NOTE: 4Q '18 factors per McDermott, Will & Emery memo dated February 20, 2019.
NEW SITE SPECIFIC STUDY (August 2017}
Decommissioning Alternative* SAFSTOR Cost escallation rate 2.91%
Obtained from KCC Docket 18-WCNE-107-GIE (2017 $s) (Q1 2019 $s) (2045 $s)
SAFSTOR Period Millions Millions Millions % Total Radioactive Systems/Structures and License Termination $ 980.8 $ 1,024.5 $ 2,189.7 90%
Preparation for Decommissioning/Spent Fuel Mgmt $ 58.1 $ 60.7 $ 129.7 5%
Other Systems/Structures and Site Restoration $ 54.2 $ 56.7 $ 121.1 5%
Subtotal - Not Applicable to NRC Minimum $ 112.3 $ 117.3 $ 250.8 10%
TOTAL COST ESTIMATE $ 1,093.1 $ 1,141.9 $ 2,440.6 100%
August 2017 study is approved by the KCC for the SAFSTOR method.
I I
I .
~OLF CREEK NUCLEAR OPERATING CORPORATION .
Decommissioning Funding Status Report as of December 31, 2018 10 CFR 50.75 (b) and (c)
(~ollars In Thousands)
TOTAL KGE(47%) KCPL(47%) KEPCo(6%)
jarket Value of External Sinking 497,072.9 227,462.2 244,605.2 25,005.5 Ftnd as of 12/31/18 S hedule of Amounts to be Collected (as approved by rate-selling authorities based on Site Specific Study) 2019 9,605 5,773 3,317 515 I 2020 2021 9,613 9,621 5,773 5,773 3,317 3,317 523 531 2022 9,629 5,773 3,317 539 2023 9,637 5,773 3,317 547 2024 9,645 . 5,773 3,317 555 2025 9,653 5,773 3,317 ,563 2026 9,662 5,773 3,317
- 572 2027 . 9,670 5,773
- 3,317 580 2028 9,679 5,773 3,317 589 2029 9,688 5,773 3,317 598 2030 9,697 5,773 3;317 607 2031 9,706 5,773 3,317 616 2032 9,715 5,773 3,317 625 2033 9,725 5,773 3,317 635 2034 9,734 5,773 3,317 644 2035 9,744 5,773 3,317 654 2036 9,754 5,773 3,317 664 2037 9,764 5,773 3,317 674 2038 9,774 5,773 3,317 684 2039 9,784 5,773 3,317 ' 694 2040 9,794 5,773 3,317 704 2041 9,805 5,773 3,317 715 2042 9,816 5,773 3,317 726
~~: rn~ HH 3,317 736 l
3,317 748 829 0 254,848 151,541 87,071 16,236 A umohons re* Rates/Factors soeclflc to Owner and Jurisdiction cbst Escalation Rate Prior Current Prior Current Prior Current obtained from KCC Docket 15-WCNE-093-GIE 18-WCNE-107-GIE 15-WCNE-093-GIE 18-WCNE-107-GIE 15-WCNE-093-GIE '18-WCNE-107-GIE 3.15% 2.91% 3.15% 2.91% 3.15% 2.91%
oltained from MPSC Docket E0-2018-0062 E0-2018-0062 N/A N/A 3.16% 3.1,6% NIA NIA Aner Tax Earnings on Funds
- From KCC Docket 1B-KCPE-480-RTS 2012- 2025 5.60% TBD 2012 -2025 5.84% 2018-2084 4.62% 2012 -2025 6.74% TBD 2026-2035 4.83% TBD 2026 - 2045 deer - .25%/year 2085 -2091 3.95%
! 2036-2044 2045 - Decommissioning 3.83% TBD 2045 - Decommissioning deer - .13%/year 2092-2097 3.45%
2026-2035 2036-2044 5.33%
4.15%
TBD TBD 2.~1% TBD 2098-2106 2.09% 2045 - Decommissioning 1.93% TBD I. .
M1ssoun 1
2012-2025 5.18% 5.46%
1* 2026 - 2045 deer - .154%/year deer- ,16%/year 2045 - Decommissioning deer - .022%/year deer - .04%/year I
Power sale contracts None None None None None None Jodificatlons to method of financial assurance None None None None None , No*ne I
Material changes to trust agreements None None None None None None I
I
WOLF CREEK NUCLEAR OP.ERATING CORPORATION Decommissioning Funding Status Report as of December 31, 2018 10 CFR.50.75 (b) and (c)
(Dollars in Thousands)
Kansas FERC TOTAL KGE Market Value of External Sinking $ 227,462.2 Fund as of 12/31/18 Schedule of Amounts to be Collected (as approved by rate-setting authorities based on Site Specific Study) 2019 5.477,274 , 295,426 5,772,700 5,773 2020 5,477,274 295,426 5,772,700 5,773 2021 5,477,274 295,426 5,772,700 5,773 2022 . 5,477,274 295,426 5,772,700 5,773 2023 5.477,274 295.426 5,772,700 5,773
- 2024 5,477,274 295,426 5,772,700 5,773 2025 5,477,274 295,426 5,772,700
- 5,773 2026 5,477,274 295,426 5,772,700 5,773 2027 5,477,274 295,426 5,772,700 5,773 2028 5,477,274 295,426 5,772,?00 5,773 2029 5,477,274 295.426 5,772,700 5,773 2030 5.477,274 295,426 5,772,700 5,773 2031 5,477,274 295.426 5,772,700 5,773 2032 5,477,274 295,426 5,772,700 5,773 2033 5.477,274 295,426 5,772,700 5,773 2034 5,477,274 295,426 5,772,700 5,773 2035 5.477,274 295.426 5,772,700 5,773 2036 5,477,274 295,426 5,772,700 5,773 2037 5,477,274 295,426 5,772,700 5,773 2038 5.477,274 295,426 5,772,700 5,773 2039 5.477,274 295,426 5,772,700 *5,773 2040 5,477,274 295,426 5,772,700 5,773 2041 5,477,274 295.426 5,772,700 5,773 2042 5.477,274 295,426 5,772,700 5,773 2043 5,477,274 295,426 5,772,700 5,773 2044 5,477,274 295,426 5,772,700 5,773 2045 1,369,319 73,857 1,443,176 1443 151,541 Assum11tions re: Rates/Factors s11ecific to Owner and Jurisdiction Prior Current Cost Escalation Rate Obtained from KCC Docket 15-WCNE-093-GIE Kansas 3.15% Obtained from KCC Docket 18-WCNE-107-GIE 2.91%
Missouri N/A N/A After Tax Earnings on Funds Kansas 2015 - 2025 5.60% TBD 2026 - 2035 4.83% TBD 2036-2044 3.83% TBD 2045 - Decommissioning 2.31% TBD Missouri Power sale contracts None None Modifications to method of financial assurance None None Material changes* to trust agreements None None
WOLF CREEK NUCLEAR OPERATING CORPORATION Decommissioning Funding Status Report as of Declj!mber 31, 2018 1o CFR 50. 75 (b) and (c) *
(Dollars In Thousands)
Kansas Missouri TOTAL KCPL Marl<et Value of External Sinking $ 244,605.2 Fund.as of 12/31/18
- Schedule of Amounts to be Collected (as approved by rate-setting authorities based on Site Specific Study) 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 2.045 509,058 320,316 829,374 _ _ _ _ _;;;82"'9'-
87,071 Assumptions re: Rates/Factors specific to Owner and Jurisdiction Cost Escalation Rate Prior Current
.Obtained from KCC Docket 15-WCNE-093-GIE Kansas 3.15% 9btained from KCC Docket 18-WCNE-107-GIE 2.91%
Obtained from MPSC Docket E0-2018-0062 Missouri .3.16% Obtained from MPSC Docket E0-2018-0062 3.16%
After Tax Earnings on Funds Kansas 2018 - 2029 5.84% 2018 - 2084 4.62%
2030-2045 deer - .25%/year 2085- 2091 3.95%
2045 - Decommissioning deer - .13%/year 2092-2097 3.45%
2098 - 2106 2.09%
Missouri 2018 - 2027 5.18% 5.46%
2028 -2047 deer- .154%/year deer - .16%/year 2048 - Decommissioning deer - .022%/year deer - .04%/year Power sale contracts None None Modifications to method of financial assurance None None Material changes to trust agreements None None
./ ' ' *\
WOLF CREEK NUCLEAR OPERATING CORPORATION Decommissioning Funding Status Report.as of December 31, 2018 10 CFR 50.75 (b) and (c)
(Dollars in Thousands)
KEPCo Market Value of External Sinking 25,005.5 Fund as of 12/31/18 Schedule of Amounts to be Collected (as approved by rate-setting authorities based on Site Specific Study) 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 16,236 Assumptions re: Rates/Factors specific to Owner and Jurisdiction Cost Escalation Rate Prior Current Obtained from KCC Docket 15-WCNE-093-GIE Kansas 3.15% Obtained from KCC Docket 18-WCNE-107-GIE 2.91%
Missouri NIA N/A After Tax Earnings on Funds Kansas 2015- 2025 6.74% TBD 2026 - 2035 5.33% TBD 2036 - 2043 4.15% TBD 2044 - Decommissioning 1.93% TBD Missouri Power sale contracts None None Modifications to method of financial assurance None Material changes to trust agreements None None
UMB 1010 Grand Boulevard Kansas City, MO 64106 800.545.6101 Account Name KANSAS GAS & ELECTRIC WOLF CREEK GENERATING STATION DECOM TRUST Account Number 116889 Statement Period Dec. 1 - Dec. 31 , 2018
-- - --- manifest line------ - -- Administrator Anthony Hawkins 816.860 .3014 l1111111**l*1*l*l1*111111111111*11l1llll1** 11llll, 1l1*1ll111*1ll* anthony.hawkins@umb.com KANSAS GAS AND ELECTRI C COMPANY Associate Administrator Melissa Byers McGee ATTN : SUSAN NORTH 816-860-3202
% WESTAR ENERGY melissa.byersmcgee@umb.co m PO BOX 889 Senior Officer Douglas Hare TOPEKA KS 66601 -0889 816.860.3006 douglas.hare@umb.com Philomene Bennett The Ninth Day Oil on canvas 00?604 114
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UMB Account Name: KANSAS GAS & ELECTRIC WOLF CREEK GENERATING STATION DECOM TRUST Account Number: 116889 Statement Period : Dec. 1 - Dec. 31, 2018 Page 3 of 7 Market Overview Asset Allocation Current Period Year-to-Date 12/01/2018 01/01/2018 Beginning Market Value 238,187,826.57 237 I 102,282,59 Income Dividends 94.86 5,159,589 .64 Other Income 97 ,394.16 893 ,632.07 Net Contributions/Distributions Receipts 97,488.53 14,086,898 .23 Disbursements (97,488.53) (9,478,868 .35) Account Value Expenses/Fees (6,863,692.42) Percentage Market Value Capital Gain Distributions Equity Funds 53% $119,800,451 Change in Market Value (1 0,823 ,154. 69) (13,437,680.86) Fixed Income Funds 29% $64,923,859 Ending Market Value 227 ,462,160.90 227 ,462,160.90
- Real Estate / Oil & Gas Unique Assets 17%
1% $3,241,109
$39 ,368,885 Capital Gains Short-term Capital Gain/ (Loss)
Long -term Capital Gain / (Loss)
Current Period 441 ,735.37 4,248,464.01 Year-to-Date 1,019,557.39 15,404, 117.57
- Money Markets and Cash < 1%
100%
$127,857
$227,462,161 Historical Value 250,000,000 225,000,000 200,000,000 175,000,000 150,000,000 125,000,000 100,000,000 75,000,000 50 ,000,000 25,000,000 0 ....l___ _.L_...L.J:_ L.L--1.J:._-1....JL._.1....C..-- - - ' - - ' - ~-l.....<.----'-------'--'---'--
D J F M A M J J A S O N D 002604 ?/4
UMB Acco unt Name: KANSAS GAS & ELECTRIC WOLF CREEK GENERATING STATION DECOM TRUST Acco unt Number: 116889 Statement Period : Dec. 1 - Dec. 31 , 2018 Page 4 of 7 Portfolio(s) included in Statement Portfo lio Number: 116889.1 Portfo lio Name: KG&E Wolf Creek Decom Tr CASH AC Pri Usd 116889.2 KG&E Wolf Crk Decom Tr - SEI Inv Mgmt 116889.8 KG&E Wolf Creek Decom Tr-CrossCreek (LP) 116889.16 KG&E Wolf Creek Decom Tr-CrossCreek LLC 116889.24 KG&E Wolf Creek Decom Tr-SEI Struc Cr LP 116889.25 KG&E Wolf Creek Tr-CrossCreekCap Ill LP 116889.26 KG&E Wolf Creek Tr-CrossCreekCap IV LP 116889.27 KG&E Wolf Creek Decom Tr-SEI Core Prop 116889.28 KG&E Wolf Creek Tr-CrossCreek Cap V L.P.
Transaction Summary Market Value Income Cash Princieal Cash Cost lncludina Cash Beginning Market Value 0.00 0.00 222,607,285.31 238,187,826.57 Income Dividends 94.86 94.86 Other Income 97,394.16 97,394.16 Additions Transfers 97,488 .53 97,488 .53 Disbursements Other (97,488 .53) (97,488.53)
Purchases (140 ,258.98) 5,030,890.73 4,890 ,631 .75 Sales & Maturities 42,769.96 (42 ,769 .96)
Non Cash Changes 6,105.39 6,105.39 Change in Market Value (15,719,891.83)
Ending Market Value 0.00 0.00 227,601 ,511.47 227 ,462, 160.90 Statement of Accruals Units Asset Descrietion Pa~able Date Rate Amount Dividend 127,857.26 Fidelity Treasury Fund #2016 01/01/2019 0.001 87.04 3,750,296.065 SEI Core Fixed Income Fund 01/01/2019 0.031 115,375.93 2,298,412.64 SEI High Yield Bond Fund 01/02/2019 0.051 117,807.52 718,720.581 SEI SIIT Dynamic Asset Allocation Fund 12/31/2018 0.127 90,990 .03 4,123,068.211 SEI SIIT S & P 500 Index Fd Cl A 12/31/2018 0.097 401,586.84
UMB Account Name: KANSAS GAS & ELECTRIC WOLF CREEK GENERATING STATION DECOM TRUST Acco unt Number: 116889 Statement Period: Dec. 1 - Dec. 31 , 2018 Page 5 of 7 Statement of Accruals (continued)
Units Asset Description Payable Date Rate Amount Dividend 2,590,432.11 SEI SIIT World Equity EX-US Fund Cl A 12/31/2018 0.281 728,170.47 883,840.371 SIIT Emerging Markets Equity Fund 12/31/2018 0.192 169,432.20 Total Dividend 1,623,450.03 Total Accruals 1,623,450.03 002604 3/4
UMB Account Name: KANSAS GAS & ELECTRIC WOLF CREEK GENERATI NG STATION DECOM TRUST Account Number: 116889 Statement Period : Dec. 1 - Dec. 31 , 2018 Page 6 of 7 Statement of Investment Position Cost Basis Market Value Estimated Symbol Unrealized Annual Yield Units Descrietion Cusip Unit Total Unit Total Gain / (Loss) Income %
iffidh:Ha Equity Fund 718,720.581 SEI SIIT Dynamic Asset Allocation Fund SDLAX 11 .84 8,508,595.15 17.91 12,872,285.61 4,363,690.46 91 ,278 0.71 783980683 1,685,594.478 SEI SIIT Emerging Market Debt Fund Cl A SEDAX 10.23 17,246,972.40 9.15 15,423,189.47 (1,823,782.93) 488,822 3.17 783980758 4,123,068.211 SEI SIIT S & P 500 Index Fd Cl A 15.49 63,877,502.60 13.41 55,290,344.71 (8,587,157.89) 1,364,736 2.47 783980626 2,590,432 .11 SEI SIIT World Equity EX- US Fund Cl A WEUSX 10.33 26,760,954.12 11.08 28,701,987.78 1,941 ,033.66 727,911 2.54 783980774 883,840.371 SIIT Emerging Markets Equity Fund SMQFX 9.58 8,464,840.59 8.50 7,512,643.15 (952,197.44) 169,697 2.26 783980618 Total Equity Fund 124,858,864.86 119,800,450.72 (5,058,414.14) 2,842,444 Total Equity Funds 124,858,864.86 119,800,450.72 (5,058,414.14) 2,842,444
- M*i:i+i,,iii'lri*t-Fixed Income Funds 3,750,296.065 SEI Core Fixed Income Fund SCOAX 10.30 38,609,685.70 9.98 37,427,954.73 (1,181,730.97) 1,173,174 3.13 783980204 2,298,412.64 SEI High Yield Bond Fund SGYAX 8.94 20,540,187.63 8.22 18,892,951 .90 (1,647,235.73) 1,248,288 6.61 783980303 918,137.888 SEI SIIT Small Mid Cap Equity Fd SSMAX 12.75 11 ,710,348.56 9.37 8,602,952.01 (3,107,396.55) 112,013 1.30 783980816 Total Fixed Income Funds 70,860,221.89 64,923,858.64 (5,936,363.25) 2,533,475 Total Fixed Income Funds 70,860,221.89 64,923,858.64 (5,936,363.25) 2,533,475 11i1¥iffiil*fitJit-Real Estate / Oil & Gas 1 Cross Creek Capital, L.P. 2,146,283.85 2,146,283.85 1,729,11 1.73 1,729,111.73 (417,172.12) 0 A Delaware Limited Partnership 1 Cross Creek Capital Partners LLC 1,864,283.61 1,864,283.61 1,511,997.43 1,511,997.43 (352,286.18) 0 a Delaware limited liability company Total Real Estate/ Oil & Gas 4,010,567.46 3,241,109.16 (769,458.30) 0 Total Real Estate/ Oil & Gas 4,010,567.46 3,241,109.16 (769,458.30) 0
UMB Accou nt Name: KANSAS GAS & ELECTRIC WOLF CREEK GENERATING STATION DECOM TRUST Account Number: 116889 Stateme nt Perio d : Dec. 1 - Dec. 31 , 2018 Page 7 of 7 Statement of Investment Position (continued)
Cost Basis Market Value Estimated Symbol Unrealized Annual Yield Units Description Cusip Unit Total Unit Total Gain / (Loss) Income %
Unique Assets Unique Assets 1 Cross Creek Capital Partners Ill LP 1,554,000.00 1,554,000.00 1,970,901.41 1,970,901.41 416,901 .41 0 1 Cross Creek Capital Partners IV LP 1,000,000.00 1,000,000.00 1,043,587.00 1,043,587.00 43,587.00 0 1 Cross Creek Partners V LP 690,000.00 690,000.00 502,405.00 502,405.00 (187,595.00) 0 5,108.79 SEI Core Property Fund LP 1,859.54 9,500,000.00 2,304.76 11 ,774,510.34 2,274,510.34 0 8,879.44 SEI Structured Credit LP 1,689.30 15,000,000.00 2,711 .60 24,077,481.37 9,077,481.37 0 Total Unique Assets 27,744,000.00 39,368,885.12 11 ,624,885.12 0 Total Unique Assets 27,744,000.00 39,368,885.12 11,624,885.12 0
- 1M:fi'IMfl@d;l ft:-
Money Market Funds 127,857.26 Fidelity Treasury Fund #2016 FTVXX 1.00 127,857.26 1.00 127,857.26 2,2 13 1.73 31607A406 Total Money Market Funds 127,857.26 127,857.26 0.00 2,213 Total Money Markets and Cash 127,857.26 127,857.26 0.00 2,213 Account Total 227,601 ,511.47 227,462,160.90 (139,350.57) 5,378,132 00?604 414
~.
~
BNY MELLON TRDB58 B58GPLNOOOOO MONTHLY FINAL 225951 2018 31 CYCLE A 22 : 59 : 54 RUN DATE : 04 - JAN - 19 INVESTMENT DETAI L PAGE : 1 B58 GPLNOOO 31 DECEMBER 2018 M1101 KANSAS CITY P&L COMBINED PLAN KANSAS CITY P&L COMBI NED PLAN SHARES/ MARKET . UNREALIZED PAR VALUE SECURITY DESCRIPTION VALUE GAIN/LOSS INVESTMENTS UNIT OF PARTICIPATION KANSAS C ITY POWER & LIGHT 51 , 148 ,786 . 3580 KCPL WOLF CREEK KAN 71 , 891 ,3 26 .09 1 .8859 96 ,462 , 365 . 72 24 , 571 , 039 .63 78 552 140 .6470 KCP&L WOLF CREEK MO 1 06 349 070 . 65 1 .8859 148 142 817 .43 41 793 746.78 129,700 ,927.0050 1 78 ,240 ,396 .74 244 ,605 , 183 . 15 66 , 364,786 . 41 TOTAL INVESTMENTS UNIT OF PARTICIPATION 178 ,240 ,396 .74 244 ,605 , 183 . 15 66 , 364,786 .41 TOTAL INVESTMENT 1 78 ,240 ,396 .74 244 , 605 , 183 . 15 66 , 364,786 . 41
,UU TRY CLUU TRU!:, I l I< KF 1-'*,0-WOl H JI: H J > lf[ l t, L l ll t?
PORTFOLIO OVERVIEW PORTFOLIO ASSET ALLOCATION ASSET ALLOCATION CHART Estimated Estimated Yield Current Holdings Cost
- Annual Income at Market ** Market Value *** Percent Reserves $441 ,785.84 $3,417.55 0.77% $441 ,785.84 1.77%
Fixed Income 9,963 ,208.19 249,606.97 2.54 9,834 ,609.93 39.33 Equities 12,101,687.78 184,815.55 1.25 14,729,141.28 58.90 Total Account $22,506,681.81 $437,840.07 1.75% $25 ,005,537.05 100.00%
- Reserves 1.77%
- Fixed Income 39.33
- Equities 58.90 INVESTMENT GUIDELINES YEAR-TO-DATE INFORMATION Minimum Maximum Realized Gain/(Loss) Amount Reserves 0% 35% Short-Term N/ A Fixed Income 35 65 Long-Term N/ A Equities 35 65 Net Realized Gain/(Loss) N/A Earned Income Amount Past Three Months $213 ,959.80 Year-to-Date $457,984.58
- Amortized cost will be reflected where applicable.
- Estimated Yield at Market is calculated by multiplying the number of shares/ units held by the income rate and dividing by the Market Va lue. Data is suppl ied by T. Rowe Price Associates, Inc. to exist ing clients as an update on their current holdings and portfolio.
- *
- Market values include accrued income where applicable.
Note: T. Rowe Price strongly encourages you to reconcile th is statement to the statements you receive directly from your custodian, broker, or the Price Funds, as applicable, to ensure consistency. If you have any questions with respect to this statement, please contact your T. Rowe Price Portfolio Manager.
CONF,DENCE T. ROWE PRICE 2
Enclosure II to WM 19:.0008 Commission Order (Docket No. 18-WCNE-107-GIE)
(11 pages)
20180802102947
, Kansas Corporation Commission THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS Before Commissioners: Shari Feist Albrecht, Chair Jay Scott Emler Dwight D. Keen In the Matter of the 2017 Wolf Creek Triennial )
Decommissioning Financing Plan. ) Docket No. 18-WCNE-107-GIE v-ORDER 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:
- 1. .On September 1, 2017, the Wolf Creek Nuclear Operating Corporation (WCNOC),
Kansas Gas and Electric Company d/b/a Westar Energy (Westar), Kansas City Power & Light Company (KCP&L), and Kansas Electric Power Cooperative, Inc. (KEPCo) (collectively referred to as the Parties) jointly submitted the Decommissioning Financing Plan for the Wolf Creek Generating Station (Wolf Creek).
- 2. The decommissioning dockets are designed to approve a methodology, which reasonably estimates the costs to decommission Wolf Creek and set a cost escalation rate. 1 This Docket represents the eleventh review over the last thirty years of the cost to decommission Wolf Creek. 2 The Decommissioning Financing Plan includes the 2017 Triennial Decommissioning Cost Study for Wolf Creek. 3 TLG Services, Inc. prepared the Decommissioning Cost Analysis for WCNOC. TLG's Decommissioning Cost Analysis offered two decommissioning cost estimate 1
Transcript (Tr.), p. 7.
2Jd.
3 Joint Pleading Regarding Decommissioning Financing Plan, Sep. 1, 2017.
methods: DECON and SAFSTOR. In past Dockets, the Commission has approved the DECON method. 4
- 3. Since Wolf Creek's last Decommissioning Cost Analysis in 2014, the question whether the federal government will remove the spent fuel from Wolf Creek .upon its decommissioning remains a major concern. 5 As a result, in the 15-WCNE-093-GIE Docket, the Commission directed WCNOC to provide a cost estimate that includes long-term on-site storage of spent fuel. 6 In response, TLG produced Appendix E, which includes some assumptions that the federal government would not timely remove the spent fuel. 7 TLG included those assumptions in Appendix E of its 2017 Decommissioning Cost Analysis, but noted, "[b ]ecause 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 overalLupdated cost estimate in this report."8 Appendix E gave rise to a third decommissioning scenario: DECON Alternative with Long-Term Spent Fuel Management (DECON ALT).
- 4. WCNOC's Application contained three decommissioning cost estimate methods and a single cost escalation rate. 9 The cost escalation rate is not disputed. The three cost estimate methods are: (1) DECON; (2) DECON Alternative with Long-Term* Spent Fuel Management (DECON ALT); and (3) SAFSTOR. 10 DECON assumes the U.S. Department of Energy will take the spent fuel at the time of decommissioning. 11 DECON ALT includes costs associated with on-4 Direct Testimony ofLeo M. Haynos (Haynos Direct), May 15, 2018, p. 6.
5 Attachment 2 to Triennial Wolf Creek Decommissioning Cost Study (Study Attachment 2), Aug. 2017, p. 130 of 139.
6 Haynos Direct, p. 11.
7 Id.; Study Attachment 2, p. 130.
8 ld.
9 Tr., p. 8.
io Id.
11 Jd.
2
site storage of spent fuel for an extended period of time after decommissioning. 12 Both DECON
- methods assume the spent fuel will be removed from the plant, whereas under SAFSTOR, the spent fuel remains at the facility. 13 SAFSTOR is a deferred decontamination, where the unit is shut down and safely stored until the unit is removed over a sixty-year timeframe. 14 The total cost for DECON is $814 million (ending in 2053). 15 The total cost for DECON ALT is $1.09 billion (ending in year 2075). 16 The total cost for SAFSTORis $1.09 billion (endingin2106). 17 DECON
.and*SAFSTOR have similar engineering, planning, and site preparation requirements. 18
- 5. On May 15, 2018, Adam Gatewood and Leo Haynos filed testimony on behalf of Commission Staff (Staff). Gatewood recommended the Commissioi;i adopt the inflation forecasts proposed by TLG. 19 Haynos testified that TLG is a nationally renowned engineering firm specializing in decommissioning nuclear plants and that their decommissioning estimates are reasonable. 20 Due to the U.S. Department of Energy's failure to develop a plan to dispose.of spent nuclear fuel from commercial nuclear generating plants, Haynos recommended. that any estimate should consider the costs of on-site storage. 21 Haynos* concluded:
Because of the uncertainty in DOE accepting spent fuel, I recommend the Commission consider the Appendix E cost estimate [DECON ALT] as the appropriate methodology for accumulating sufficient funds to decommission
-the Wolf Creek site. In consideration of the industry's hesitancy in acknowledging DOE's failure to date to accept spent fuel, the Commission alternatively could approve the SAFSTOR estimate as the appropriate methodology for the decommissioning financing plan. 22 i2 Id.
13 Haynos Direct, p. 7.
14 Id.; Study Attachment 2, pp. 8-9 of 139.
15 Haynos Direct, p. 13.
16 !d.
11 Id.
18 Study Attachment 2, pp. 38-39 of 139.
19 Direct Testimony of Adam H. Gatewood, May 15, 2018, p. 3.
20 Haynos Direct, pp. 8-9.
21 Id., p. 12.
22 /d. ,p. 13.
3
- 6. On June 12, 2018, Larry Wilkus filed Rebuttal Testimony, explaining that in developing the cost estimate and the resulting impact on rates to fund Westar's and KCP&L's decommissioning trust funds, WCNOC had assumed the Commission would continue to rely on the DECON method. 23 Accordingly, if the Commission adopted either of the methods recommended by Haynos (DECON ALT or SAFSTOR), the utilities would need to collect more money from customers to fund their decommissioning trust funds. 24 Wilkus requested recovery of the additional funds through energy cost adjustments in the pending Westar and KCP&L rate cases. 25
- 7. On June 18, 2018, the Citizens Utility Ratepayer Board (CURB)26 filed the Surrebuttal/Reply Testimony of Stacey Harden, in response to Wilkus's testimony that any increased funding level of the decommissioning trust in this Docket should be recovered through Westar's and KCP&L's RECA Tariffs. 27 Harden testifies that Wilkus's testimony recommending the Commission approve a specific ratemaking ~eatment for the potential increased funding level is premature and that the Annual Contribution level should continue to be part of base rates, to be determined in the pending KCP&L and Westar rate cases. 28
- 8. On June 22, 2018, WCNOC 29 and Staff filed a Joint Motion to Approve Settlement .
and Agreement. Under. the proposed Settlement and Agreement, the Commission would adopt the DECON ALT methodology in its Decommissioning Cost Analysis. Under the DECON ALT methodology, the Signatories agree $1.088 billion in 2017 dollars is the costfor decommissioning funding and for use by Westar, KCP&L and KEPCo in setting funding levels for each company's 23 Rebuttal Testimony of Larry Wilkus, June 12, 2018, p. 4.
24 Jd: .
25 Jd., p. 6.
26 CURB was granted intervention on September 19, 2017.
27 Surrebuttal/Reply Testimony of Stacey Harden, June 18, 2018, p. 3.
28 Jd., p. 5.
29 Westar and KCP&L each own 47% ofWCNOC. KEPCo owns the remaining 6%.
4
respective Decommissioning Trust Account. 30 The owners of Wolf Creek agree to use an annual 2.91 % escalation rate to escalate the 2017 decommissioning cost estimate from 2017 dollars to the appropriate dollar amount in the year the decommissioning costs occur. 31 CURB is opposed to the proposed Settlement.
- 9. On June 27, 2018, Wilkus, Gatewood, and Haynos filed testimony in support of the settlement; and Harden of CURB, filed testimony opposing the settlement. CURB's primary concern in opposing the settlement was the DECON ALT plan results in a significant increase in the ~ecommissioning cost estimate. 32
- 10. On June 29, 2018, Wilkus, Gatewood, and Haynos each filed rebuttal testimony in support of the proposed settlement. In his testimony, Wilkus explained adopting the DEC ON ALT plan would increase Westar's annual revenue requirement by approximately $2 million and KCP&L's by approximately $1.2 million. 33 The increased revenue requirement constitutes about a one-tenth of I% increase for Westar and less than 0.02% increase for KCP&L. 34
- 11. On July 10, 2018, the Commission held an Evidentiary Hearing. WCNOC, Staff, and CURB appeared by counsel. The Commission heard live testimony from a total of five witnesses, including two on behalf of WCNOC, one on behalf of CURB, and two on behalf of Staff. 35 The parties had the opportunity to cross-examine the witnesses at the evidentiary hearing and to redirect their own witnesses. CURB did not dispute the numbers proposed by TLG regarding the Wolf Creek decommissioning costs, but argued the numbers were based on 30 Non-Unanimous Settlement Agreement, June 22, 2018, ~ 4.
31 Jd., ~ 5.
32 Testimony in Opposition to Settlement of Stacey Harden, June 28, 2018, p. 4.
33 Responsive Testimony is Suppm1 of Stipulation and Agreement of Larry Wilkus, June 29, 2018, p. 2.
34 Id., pp. 2-3.
35 See Tr. p. 3.
5
speculation and assumptions. 36 Accordingly, CURB asserts the Settlement* Agreement is not supported by substantial, competent evidence. 37
- 12. At the hearing, CURB stated:
CURB simply requests the Commission to reject the Settlement Agreement as proposed by the parties and instead take a long, hard look at the evidence and all the options presented to the Commission available in the TLG plan and make the best decision possible. 38 While CURB contends there is not substantial evidence to support using DECON ALT as a decommissioning scenario, it does not contest the 2.91 % escalation rate agreed to in the Settlement Agreement. Since the recommended 2.91 % escalation rate is uncontested, the Commission finds it appropriate to apply the 2.91 % escalation rate to whichever decommissioning scenario it selects.
- 13. As CURB .and Staff note, TLG openly acknowledges the speculative nature of the DECON ALT decommissioning scenario. 39 Similarly, Haynos explains this Docket represents the first time TLG has presented a formal study detailing the DECON ALT scenario. 40 In th~ last Triennial Review, Haynos recommended considering interim long-term storage, but was unable to recommend a methodology with interim long-term storage because TLG had not presented an in-:-
depth cost estimate for interim long-te~ storage. 41 Appendix E represents the first time the Commission has been presented with an estimate instead of a conceptual approach. 42
- 14. Even though TLG offers a cost estimate for the DECON ALT decommissioning scenario, the Commission remains concerned that DECON ALT is too speculative. All of the parties to the Docket agree that the DECON ALT method is speculative. Rather than adopt a 36 Tr., pp. 11-12.
37 Id., p. 12.
38 Tr., pp. 13-14.
39 See id., p. 27; Haynos Direct, p. 11; Study'Attachment 2, p. 130 of 139.
40 Tr., p. 79.
41 Id., pp. 82-83.
42 fd.
6
methodology reliant on unsubstantiated speculation, the Commission prefers a *methodology that has been endorsed by the Nuclear Regulatory Commission (NRC).
- 15. In 1988, the NRC announced decommissioning requirements for licensed nuclear power facilities. 43 The NRC defined three acceptable decommissioning alternatives: (1) DECON, (2) SAFSTOR, and (3) ENTOMB. Under DECON, portions of a facility and site containing radioactive contaminants are removed or decontaminated to a level where the property can be used without restriction after the plant closes. 44 Under SAFSTOR, the nuclear facility is safely stored and decontaminated to a level where the property can be used without restriction within 60 years. 45 Under ENTOMB, radioactive contaminants are encased in concrete until the radioactive material decays to a level permitting unrestricted use of the property. 46 In March 2017, the NRC staff proposed removing the ENTOMB option from existing guidance documents, deeming. it impracticable. 47 None of the parties advocate for the ENTOMB method. As there is no evidence in the record to support the ENTOMB method, the Commission will not consider it as a viable option.
- 16. Since 1989, the NRC's Information Digest indicates eighteen reactors have been shut down. 48 DECON was the decommissioning alternative selected for nine of those reactors, SAFSTOR was selected for five, and the remaining four were initially placed in safe-storage before switching to DECON. 49\,_ In choosing between DECON and SAFSTOR, the Commission believes it would be extremely irresponsible to select a methodology that assumes the federal government will be able to accept the spent fuel at the time of decommissioning. There is no evidence that the 43 Study Attachment 2, p. 8 of 139.
44 Id.
45 Id., pp. 8-9.
46 Id., p. 9.
47 id.
48 Attachment 7 to Triennial Wolf Creek Decommissioning Cost Study (Study Attachment 7), Aug. 2017, p. 4 of 20.
49 Id., pp. 4-5 of 20.
7
federal government has any plan to collect and remove the spent* fuel. Accordingly, the Commission is gravely concerned that adopting any methodology that does not factor in on-site storage would subject future generations to massive unfunded decommissioning costs, resulting in rate shock. To avoid future rate shock, the Commission is left with two options: DECON ALT or SAFSTOR.
- 17. The cost estimate for SAFSTOR and DECON ALT are roughly the same in today's dollars, so but 80% of DEC ON ALT spending occurs from 2045-2050, shortly after the plant is shut down. 51 Under SAFSTOR, only about 30% of the spending occurs during that timeframe, with 43% of the spending occurring between 2100 and 2106. 52
- 18. The Commission fin4s SAFSTOR is the best cost estimate methodology for decommissioning Wolf Creek. Unlike DECON ALT, SAFSTOR is one of the three cost estimate methodologies recognized by the NRC.
- The Commission gives great weight to *the NRC's, recognition of SAFSTOR as an appropriate cost estimate. DECON ALT appears to be a hybrid of DECON and SAFSTOR that has b~en used in four decommissionings since 1989,53 but has not been officially recognized by NRC. Therefore, while the Commission finds SAFSTOR is the best cost estimate methodology for decommissioning Wolf Creek based on the available evidence, if WCNOC believes DECON ALT is a better cost estimate methodology, the Commission encourages WCNOC to present a more detailed Appendix E in its next Triennial Review.
50 Tr., pp. 32-33; Haynos Direct, p. 13.
51 Jd.
52 Id.
53 See Study Attachment 7, p. 4 of 20.
8
THEREFORE, THE COMMISSION ORDERS:
A. The Joint Motion to Approve Settlement and Agreement is denied.
B. The SAFSTOR cost estimate methodology will be
- used to calculate decommissioning* costs for Wolf Creek. The 2.91 % escalation rate agreed to by the parties is approved.
C. Any party may file and serve a petition for reconsideration pursuant to the requirements and time limits established by K.S.A.77-529(a)(l). 54 D. The Commission retains jurisdiction over the subject matter and parties to enter further orders as it deems necessary.
BY THE COMMISSION IT IS SO ORDERED.
Albrecht, Chair; Emler, Commissioner; Keen, Commissioner 08/02/2018 Dated: - - - - - - - - - -
~
~
L1 * ~r-*
-:-:,R._*
~
LynnM. Retz Secretary to the Commission BGF 54 K.S.A. 66-l'18b; K.S.A.77-503(c); K.S.A.77-53l(b).
9
CERTIFICATE OF SERVICE 18-WCNE-107-GIE I, the undersigned, certify that the true copy of the attached Order has been served to the following _parties by means of 08/02/2018 electronic service o n - - - - - - - - - -
CARY CATCHPOLE, ACCOUNTANT/ECONOMIST THOMAS J. CONNORS, ATIORNEY AT LAW CITIZENS' UTILITY RATEPAYER BOARD CITIZENS' UTILITY RATEPAYER BOARD 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 78&-271-3116 Fax: 78&-271-3116 c.catchpole@curb.kansas.gov tj.connors@curb.kansas.gov TODD E. LOVE, ATIORNEY DAVID W. NICKEL, 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: 78&-271-3116 Fax: 78&-271-3116 t.love@curb.kansas.gov d.nickel@curb.kansas.gov SHONDA RABB 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
- s. rabb@curb.kansas.gov d.smith@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 19TH FLOOR (64105 ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (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 BRIAN G. FEDOTIN, DEPUTY GENERAL COUNSEL ROBERT VINCENT, LITIGATION COUNSEL KANSAS CORPORATION COMMISSION KANSAS CORPORATION COMMISSION 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 78&-271-3354 Fax: 78&-271-3354 b.fedotin@kcc.ks.gov r.vin~ent@kcc.ks.gov
CERTIFICATE OF SERVICE 18-WCNE-107-GIE WILLIAM G. RIGGINS, GENERAL COUNSEL CATHRYN J DINGES, CORPORATE COUNSEL KANSAS ELECTRIC POWER CO-OP, INC.
- KANSAS GAS & ELECTRIC CO.
600 SW CORPORATE VIEW (66615) 0/B/A WESTAR ENERGY PO BOX4877 818 S KANSAS AVE TOPEKA, KS 66604-0877 PO BOX889 Fax: 785-271-4884 TOPEKA, KS 66601-0889 briggins@kepco.org Fax: 785-575-8136 cathy. dinges@westarenergy.com DEBBIE L HENDELL, GENERAL COUNSEL AND SECRETARY WOLF CREEK NUCLEAR OPERATING CORPORATION 1550 OXEN LANE NE PO BOX 411 BURLINGTON, KS 66839 Fax: 620-364-4017 dehende3@wcnoc.com ISi DeeAnn Shupe DeeAnn Shupe
l Enclosure Ill to WM 19-0008 Direct Testimony of Adam H. Gatewood (September 12, 2018)
(93 pages)
BEFORE THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS In the Matter of the Application of )
Kansas. City Power & Light Company ) ' Docket No.
to Make Certain Changes in its Charges ) 18-KCPE-480-RTS for Electric Services. )
DIRECT TESTIMONY PREPARED BY Adam H. Gatewood UTILITIES DIVISION KANSAS CORPORATION COMMISSION September 12, 2018
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS Table of Contents Executive Summary********************************'.****************************************************************** 2 Decommissioning Trust Annual Accrual .................................................................. 3 .
Rate of Return Analysis*******:*********************************************: ...................... :................ 6 Capital Structure ........ ,............................... ;..................... :........ :................ *............ ;**::* 8
- Cost ofDebt ...... ;.. .'.............................................................. '.. ...................... '.. ............ :10 Cost of Equity Analysis ..................................... ;.............. :...................................... 10 Standards for a Just & Reasonable Rate ofReturn; ................................................. 21 KCC Proxy Group ............................................................................... :.*................... 24 Return on Equity Analysis ........ :.......................................... ;........................... :........ ;30 Discounted Cash Flow Model .. ;.............................................................................. 34
- F orecasted Growth Rates for the DCF Model.. ........................................................ 35 DCF Results .............................................................................................................. 42
,Internal Rate of Return (IRR) Analysis ... ,..................... ,....................................... :.45
- Capital Asset.Pricing Model (CAPM) Analysis ............. ;............................... :........ 47 1 Q. Would you please state your name and business address?
2 A. My name is Adam H. Gatewo~d. My business address .is 1500 Southwest Arrowhead 3 Road, Topeka, Kansas, 66604.
4 Q. Who is your employer and what-is your t~tle?
5 A. I am employed in the Utilities pivision of the Kansas Corporation Commission as a 6 Managing Fin~cial Analyst.
7 Q. What is your educational and professional background?
1
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 A. I graduated from Washburn University ;ith a B.A. in Economics and a Masters of Business, 2 Administration. I have filed testimony on cost of capital and related financial issues before 3 the Commission in more than 120 proceedings. I have also filed testimony on cost of 4 capital issues before the Federal Energy Regulatory Commission in natural gas pipeline 5 and electric transmission dockets.
6 Executive Summary 7 Q. What issues are you testifying to in this Docket?
8 A.r My testimony addresses the annual accrual for KCP&L's nuclear decommissioning trust*
9 (NDT) and the rate of return used to calculate KCP&L's revenue requirement. With 10 respect to the annual accrual for the Kansas portion ofKCP&L's NDT, I recommend that 11 an annual accrual of $2,036,230, an amount equal to its current annual accrual, based on 12 the SAFEsroR decommissioning methodology selected by the Commission in Docket 18-13 WCNE..:107-GIE. With respect to the rate of return, I recommend that the Commission
'14 adopt a rate of return of 7.07% that incorporates the 9.30% return on equity set out in the 15 Non-Unanimous Settlement approved in Docket No. 18-KCPE-095-MER (18-095). My 16 analysis in the instant Docket provides substantial competent evidence that 9.30% is a fair 17 and reasonable return for both shareholders arid ratepayers and, therefore, it should be 18 adopted by the Commission to set KCP&L's revenue requirement in this Docket.
19 Q. What documents did you review to prepare your analysis?
20 A. In preparing my rate of return analysis and recommendation, I reviewed the following I
- 21 documents directly connected to, this Docket: 18-KCPE-480-RTS (18-480) Direct 2
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS 1 Testimony, Application, the 18-095 Non-Unanimous Sf:,ttlement Agreement (S&A); and 2 data requests response to KCC #84, 85, 86, and 161. In preparing my recommendations
- 3 for KCP&L's annual NDT accrual, I reviewed the Commission's Order in 18-WCNE-107-4 GIE (18-107) issued on August 2, 2018; the Application and testimony filed in Docket 18-5 107; and responses to KCC data requests 162, 163, 164, and 258 in Docket 18-480.
6 Decommissioning Trust Annual Accrual 7 Q. Please summarize your recommendation for KCP&L's annual NDT accrual.
8 A. With respect to KCP&L's NDT for its Kansas jurisdiction, I recommend its annual accrual 9 remain unchanged from its current level of $2,036,230. My recommendation incorporates 10 the Commission's findings issued in its August 2, 2018 Order in the 18-107 Docket. In 11 that Order, the Commission adopted the SAFESTOR decommissioning methodology.
12 Q. Describe the triennial review process of the decommissioning cost estimates.
13 A. The trie~ial review is done in two phases. In phase one, the Commission reviews the 14 decommissioning cost study, sele~ts the decommissioning methodology, and decides on 15 the inflation rate to apply to the decommission cost estimate. By selecting the 16 methodology, the Commission is selecting a cost estimate that is in current-year dollars.
17 The.inflation rate is necessary to escalate those costs to the y*ear they will occur.* The sum 18 of those inflated costs is the amount that the* nuclear plant's owners must accumulate in 19 their respective NDTs. In the latest triennial review, the Commission selected the 20 SAFESTOR methodology and a 2.91 % escalation rate. Phase two determines the annual 21 accrual necessary to fully fund the owner's NDT.
3
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 Q. What amount did KCP&L propose for its Kansas NDT annual accrual?
2 A. KCP&L proposed to keep its NDT annual accrual unchanged at $2,036,230 as set in the 3 previous review in Docket No. 15--KCPE-116-RTS. This position is KCP&L's adjustment 4 CS-37 sponsored by Ronald Klote./ KCP&L filed this position prior to the Co:mrtlission's 5 decision in 18-107. We now have the 18-107 Order which selected the SAFESTOR 6 decommissioning methodology which is lengthier and more expensive than the 7 decommissioning 1,
methodology selected in previous investig_ations. My review 8 incorporates ~he costs and timing of the SAFESTOR methodology as adopted by the
/'
9
- Commission. Even with the additional costs associated with the latest decommissioning 10 cost study filed in the 18-107 Docket, the lower expected returns in. the future, and the 11 higher cost decommissioning methodology, I found that KCP&L's current contribution is 12 sufficient to fund its obligations.
13 Q. What are the fore~asted returns you recommend for the NDT?
14 A. I propose using the expected returns published by J.P. Morgan Asset Management 15 (JPMAM) in the 2018 edition of its Long-Term Capital Market Assumptions (LTCMA).
16 The following table shows the 2018 forecasts for the asset classes used in the NDT and 17 highlights the lowered forecasts. As you can see in the following table, Staff recommends 18 using expect~d returns that* are lower (on average) than those that KCP&L used in its
.19 calculations .
4
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS I
Exoected Prooosed Portfolio Performance I 2018
-- !(gP_~~ - -- .
Exoected Returns -.JPMAivt' Large Company Stocks 9.59% 6.41%1 Small Company Stocks 10.65% 7.35%1 International Stocks 8.46% 7.61%
Corporate Bonds Cash
-- __I96%
0.62%
4.2}'.Yo 2.00%
I Sources: I KCC-258 I J.P. Morgan Asset Management Long-Term Capital Market Assumptions 1
2 These are marked differences in returns for almost every asset class. Under Staffs 3 assumptions, in a portfolio of these assets, this differe11ce results in a 100 basis point 4 lower annual return from many of the years.
5 Q. Is JPMAM' s publication a reasonable source for these types. of forecasts?
6 A. Yes, J.P. Morgan's forecasts in this publication are consistent with forecasted returns by 7 other money management firms and_ reflect the expected returns of institutional portfolio 8 managers.
9 Q. Historically, what has KCP&L's NDT earned?
10 A. I performed an internal rate of return analysis on KCP&L's deposits to its NDT from 1986 11 through the present. Over that time period, KCP&L's NDT experienced an annual return 12 of 5.94% including the effects of income taxes on unrealized gains, management fees and
. 13 *'
. expenses.
14 Q. How *did you calculate the annual accrual amount?
15 A. . My calculation appears in Schedule AHG-1, which assumes the SAFES TOR methodology, 5
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 an NDT balance (net of income taxes on unrealized gains) as of June 30, 2018, forecasted 2 returns from the 2018 edition of the JPMAM-LTCMA, and the portfolio management fees 3 reported by KCP&L. The weighted forecasted returns of the portfolio across time appear 4 in Schedule AHG-2. The annual accrual is the amount that equates the cash in-flows 5 (annual accrual plus returns on the portfolio) to the cash out-flows (the decommissioning 6 expenses).
7 Q. In 18-WSEE-328-RTS you recommended a significant increase in Westar Energy 8 Inc.'s (Westar) annual accrual to fund its share of the decommissioning costs. Why 9 is KCP&L's annual .accrual remaining the same as opposed to increasing at a rate 10 similar to that of its co-owner?
11 A. There could be several factors at work to create this situation. The most direct, simplest, 12 and, therefore most likely, explanation is that KCP&L's portfolio is subject to significantly 13 lower annual expenses (management fees) than Westar's portfolio. Each owners' portfolio 14 management fees directly affect their respective expected returns over the remaining life 15 of their trust funds. To the extent that the current.management fees are reflective of those 16 paid in years past, KCP&L's lower annual expenses are the likely reason that its portfolio 17 has experienced a higher historic return than Westar' s.
18 Rate of Return Analysis 19 Q. Please discuss the framework of Staff's rate of return (ROR) analysis in this Docket.
20 A. Staffs ~OR analysis in this Docket is, in part, a continuation of the analysis that Staff 21 performed in the 18-095 Merger Docket and 18-WSEE-328-RTS Westar rate case. These 6
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 D~ckets are made interdependent by the 18-095 S&A, 1 where signing parties committed 2 to supporting an allowed return on equity (ROE) of 9.30% 2 in this Docket for KCP&L, as 3 well as the 18-WSEE-328-RTS Docket for Westar Energy (18-328). On May 24, 2018, 4 the Commission approved the Non-Unanimous Stipulation and Agreement filed in the 5 Docket 18-095 S&A. 3 An Order is due in the 18-328 rate case by September 27, 2018.
6 Q. With regard to KCP&L's ROR in this Docket, what are your findings and 7 recommendations?
8 A. The following table summarizes my recommended ROR and the components of the 9 calculation.
Staff Proposed -- KCP&L Rate of Return Updated Capital Struc!ure - Section 7 of Application Tes! yl!a_r E_11de~_ ~ept~mbl!r 30, ~0!} U!llh!te~ t~ June 3!)_! 2018 Weighted Weight Cost Cost Long-term Debt 50.91% 4.93% 2.51%
Common Equity 49.09% 9.30% 4.57%
7.07%
Source: 18-KCPE-480-RTS; Response to DR#161 10 11 As a point of comparison, KCP&L's Application is based on the following ROR.
1 Non-Unanimous Settlement Agreement; l 8-KCPE-095-MER; filed March 17, 2018.
2 Non-Unanimous Settlement Agreement; 18-KCPE-095-MER; filed March 17, 2018; at paragraph 32, iv, l; p. 15.
3 Order Approving Merger; 18-KCPE-095-MER; Issued May 24, 2018.
7
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS
- - - - . --Return*-
- - - - - KCP&LRate .
of
_ J>_l'.!'~~-~_Rat~of Ret~n.i in Se_c,tion 7 ~( ~ppJicatio!!
Tes! year Ended September 30, 2017
~ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Weighted Weight Cost Cost Long-term Debt 50.25% 4.94% 2.48%
Conunon Equity 49.75% 9.30% 4.63%
7.Ii%
Sourc_e: 1_8-KGl'~-48_0-RTS; Sectio_n 7 Supplemental Direct Testimony of Darrin R. Ives; June 26, 2018 1
I 2 KCP&L's Application filed May 1, 2018, incorporated a 9.85% cost of common equity.
3 WitJ:i the Commission Order in 18-095 accepting the Non-Unanimous Settlement 4 Agreement, KCP&L reduced its recommende~ cost of equity request from 9.85% to 5 9.30%.
6 Setting the rate of returri requires decisions on °the cost of debt, the cost of equity, and the 7 weight of each in the 1:1tility's capital structure. Staff is preparing its revenue requirement 8 incorporating an update to June 30;2018, from the September 30, 2017, balances used in 9 the Application. The ROR that I recommend is based on the updated account balance_s and 10 costs for the capital items. The update to Section 7 results in a minor change in the ROR 11 from KCP&L's position due a small change in the capital ratios of debt and equity. I agree .
12 with the capital 'structure and. cost of debt contained in KCP&L's update.
13 Capital Structure 14 Q. Do you have any adjustments to KCP&L's capital structure?
15 A. No. I.am using the capitalization ratios of June 30, 2018.
16 Q. Is KCP&L's updated capitalization within the range. seen in the electric utility 8
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 industry?
2 A. Yes, healthy, financially sound electric utilities have traditionally employed capitalization 3 policies of about 50% debt and 50% equity. The group of electric utilities selected as the 4 proxy group for my cost of capital analysis follows this same pattern as seen in the 5 following table.
I I I Long-Tenn Debt Ratios Staff's Proxy Group 18-KCPE-480-RTS Value-Line Forecasts 2015 2016 2017 2018 2019 '21- '23 Allete Inc ALE 46.3%1 42.0%1 41.0% *41.0% 39.5%/ 40.0%
AIJjant Energy Corp LNT ~
48.6% 52.8% . 49.0%
50,0% 50.0%
50.0%
Ameren Corp AEE 49.3% 47.7% 49.5% 49.5% 49.0% 49.0%
American Electric Power Co. AEP 49.8% 50.0% 51.5% 52.5% 54.5% 50.5%
Consolidated Edison Inc ED 47.9% 50.8% 48.9% 49.0% 48.5% 48.5%_
Duke Energy Corp New DUK 48.6% 52.6% 54.0% 54,0%
- 55.0%. 56.5%
- Edison International EIX 45.0% 41.8% 45.6% 48.0% 48.0% 47.5%
El Paso Electric Co EE 52.7%< 52.7% 51.2% 53.0% 52.0% 54.5%
IDACORP Inc IDA 45.6% "44,8% -- - .
43.7% 44.0%
42.0%
. -- 44.0%
NorthWestern Corporation NWE -
53.1%
52.0% 50.2% 49.5% 48.5% 46:0:o.
OGE Energy Corp OGE 44.3% 41.1% 41.7% 43.0% 44.0% 45.5%
Pinnacle West Capital Corp PNW 43.0%* 45.6% 48.9% 48.0% 48.5% 45.5%
Portland General Electric Co. POR 47.8%
48.4% 50.1% 47.0% 50.5% 48.5%
Xcel Energy Inc XEL 54.1%: 56.3% 55.9% 58.0% 57.0% 58.0%
Average 48.3%1 48.5%1 48.7%, 49.0% 49.1%1 48.9%
Median 48.3%: 49.2% 49.3%1 49.3% 48.8% 48.5%
Min 43.0% 41.1% 41.0% 41.0% 39.5% 40.0%
Max 54.1%: 56.3%
- 55.9% 58.0% 57.0% 58.0%
Source: Value-Line Investment Survey (April 27, 2018; May 18, 2018; and June 15, 2018) I
-6 7 Q. Is KCP&L's updated capitalization consistent with the capital structure limitations 8 discussed in the 18-095 S&A?
9 A. Yes, it complies with the provisions of Attacliment 1 of the 18-095 S&A.
10* Q. Is this capitalization ratio consistent with the current capitalization of evergy, Inc. the 9
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 new merged company?
2 A. No, immediately post-merger, the holding company for KCP&L has an equity ratio in 3 excess of 61 %. 4 evergy management has stated that it intends to reduce the equity ratio to 4 a level close to 50% during the next few years. Regardless of that proposal, I would not 5 recommend using the current holding company equity ratio to establish KCP&L' s revenue _
6 requirement. It is not the lowest cost capitalization for the utility *and it is not within the 7 industry norms.
8 Cost of Debt 9 Q. Do you propose any adjustments to KCP&L's cost of debt?
10 A. As with the capital structure, I recommend an update from September 31, 2017, to June 30, 11 2018, which captures a very minor change in the embedded cost of debt..
12 Cost of Equity Analysis 13 Q. Please summarize Staff's position on KCP&L's cost of equity?
14 A. Staff recommends that the Commission authorize a 9.30% ROE, the same as that applied 15 for purposes of the Earnings Review & Sharing Plan (ERSP) that was accepted by the 16 Commission in the 18-095 Docket. KCP&L agrees with Staffs position and has 17 withdrawn its original request for a 9.85% ROE. 5 My analysis of the current capital 18 mark~ts finds that, inclusive of the benefits from the ERSP and other terms of the 18-095 4
evergy, Inc.; Form-I OQ for the period ending June 30, 2018.
5 Supplemental Direct Testimony of Darrin R. Ives, filed June 26, 2018.
10
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 S&A, an ROE of 9.30% is reasonable for KCP&L stockholders and consumers. The 2 be1:1efits that accrue to consumers through the 18-095 S&A are made available with some 3 additional risks to the shareholders. My testimony in the 18-095 Docket 6 discussed the 4 benefits and risks related to 18-095 S&A and I will summarize that discussion because they 5 ate equally important to deciding the cost of capital issues in this Docket.
6 Q. Please discuss the additional risks posed by the 18-095 S&A that was approved by the 7 Commission on May 24, 2018.
8 A. The added risks to shareholders include:
9
- a five-year rate moratorium during which KCP&L carinot file a rate case in 10 Kansas* 7 11
- upfront bill credits to KCP&L Kansas customers totaling $7,514,220; 8 12
- minimum annual credits to consumers of$2,817,832 by March 3pt of 2019, 2020, 13 2021, and 2022; 9 14 * $7,468,874 million of merger savings built into the revenue requirement in this 15 rate case* 1° and 16
- an Earnings Review and Sharing Plan for excess earnings above the 9.30%
17 allowed return for years 2020, 2021, 2022, and 2023. 11 18 Staff believes the ~ 8-095 S&A presents additional risks to shareholders because it demands 19 annual credits to consumers that has the effect oflowering KCP&L's earned return; reduces 20 the value of earnings if KCP~L earns above its allowed return; sets a period of five years 21 during which KCP&L cannot file a rate case if its earnings are less than its allowed return; 22 and sets a period of five years during which KCP&L cannot file a rate case if its capital 23 costs increase. With the 18-095 S&A in place that sets a period of five years during which 6
Testimony of Adam H. Gatewood, 18-KCPE-095-MER filed January 29, 2018; p. 11-15.
7 Order Approving Merger, issued May 24, 2018; 18-KCPE-095-MER, Attachment A, p. 45; #24.
8
_ Order Approving Merger, issued May 24, 2018; 18-KCPE-095-MER, Attachment A, p. 44; #18.
9 Order Approving Merger, issued May 24, 2018; l 8-KCPE-095-MER, Attachment A, p. 44; #18.
10 Order Approving Merger, issued May 24, 2018; 18-KCPE-095-MER, Attachment A, p. 45; #25.
11 Order Approving Merger, issued May 24, 2018; 18-KCPE-095-MER, Attachment A, p. 46; #26.
11
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 KCP&L cannot fjle a rate case, KCP&L must find cost savings equal to the guaranteed 2 fixed annual credits in order to achieve its authorized return. Consumers could also see 3 additional annual credits if the Applicant's profits exceed the 9.30% threshold. KCP&L's 4
- shareholders will retain only a portion of any earnings above the allowed return over the
.5 rate moratorium.
6 Q. Without the 18-095 S&A, would Staff be inclined to recommend a 9.30% ROE for 7 KCP&L?
8 A. Without the 18-095 S&A, Staff would likely be recommending a lower allowed return for 9 KCP&L given the current financial markets. As I discussed earlier, and in my 18-095 10 testimony, there are risks and benefits to the 18-095 S&A, primarily theERSP, a five-year 11 ratemoratorium, and the bill credits to consumers cause me to distinguish this Docket from 12 a tradi_tional rate case. Without the 18-095 S&A, Staffs recommendation- based purely 13 on the results of my financial analysis9 - could likely be\Jcloser to 9.00%. However, Staffs 14 recommendation would also have to consider the fact that a 9.00% recommendation is a 15 fuH 25 to 30 basis points b~low the lowest authorized RO_E observation in the current 16 national average and would, thus, be a highly contentious recommendation, which would
- 17 most likely result in litigation. Without the 18-095 S&A, it is likely my recommendation
- 18 would have been between 9.10% and 9.20% given the plateau seen in allowed returns 19 granted by utility regulatory commissions over the last several quarters and the fact that a 20 9.00% return is well below the lowest observation in the recent.national average. 12 12 RRA Regulatory Focus Major Rate Case Decisions: January - June 2018; S&P Global Market Intelligence; July 17,2018;p. 10. .
12
Direct Testimony of Adam H. Gatewood . Docket No. 18-KCPE-480-RTS 1 Q. Is Staff recommending an ROE range forthe Commission?
2 A. I recommend the Commission adopt a 9.30% ROE, the same that is used in the ERSP. If, 3 for some reason the Commission finds a need to deviate from the 9.30% ROE, then I 4 recommend that a range of 9 .10% to 9 .50%, which is consistent with the terms of the 18-
- 5. 095 S&A. 13 , This range is fully supported by niy cost of equity analysis specific to the risks
- 6 ofKCP&L in this Docket.
7 Q. Do you believe the Commission. can deviate from the 9.30% ROE even though it adopted th~ 18-095 S&A? \
9 A. Yes, certainly that is well within the Commission's rights if it believes the evidence cannot 10 support the allowed return sought in the 18-095 S&A. If the Commission adopts an ROE 11 lower than 9.30%, KCP&L has the option of shortening the rate moratorium from five 12
- years to three years. Staff believes there are benefits for consumers to the full five-year 13 rate moratorium that may not be present in a three-year moratorium, such as an incentive 14 to capture merger relat~d synergies and a period of relative rate stability. Those are two 15 examples that are not easily quantified but Staff believes them to be beneficial to-16 consumers.
17 Q. How does a 9.30% ROE compare to recent decisions from around the country?
18 A. A 9.30% return on equity is at the low-end of recent observations for electric utility rate 19 cases. For the first six;.months of 2018, the average ROE granted was 9.74% with thirteen 13 Non-Unanimous Settlement Agreement; 18-KCPE-095-MER filed March 17, 2018; at paragraph 32, iv, I; p. 15.
13
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 observations. 14 This group of observations includes only those decisions associated with 2 vertically integrated (generation, transmission, and distribution services) electric utilities 3 and not tied to a limited-issue rider. Over the past decade, allowed returns have declined 4 nationally, although the rate at which those declines* have occurred has varied across 5 jurisdictions. That decline happened at a more rapid pace in Kansas than in most other 6 jurisdictions. Reviewing decisions of the past year, there appears to be a plateau in allowed 7 returns; that is the rate of decline has fallen off although clearly the allowed returns are 8 significantly lower than those granted in the past. Graphs of allowed returns appear on 9 page 20 and 21.
Major Rate Case Decisions: January- June 2018 1/18/2018 Kentucky Power Co. KY 9.70%
1/31/2018 -_ P~tiic s~~i6e C~mpany ofOklahoma OK 9.30%
2/2/2018 Intei:_s~te Pow~r ~n_d Ligh! Co. IA 9.98%
2/23/20.18 Duke Energy Progres_s, LLC NC 9.90%
3/12/2018 ALLETTE _(Minn _Pwr) MN 9.25%
3/29/2018 Consumer E!]ergy Co. MI 10.00%
4/12/2018
- I~~~ana Michigan Power Co. __ .. MI 9.90%
4/13/2018 Duke Energy Kentucky, Inc. KY 9.73%
4/18/2018 DTE Electric Co. MI 10.00%
4/26/2018 Avista Corp. ___________ WA 9.50%
5/30/2018 Indiana Michigan Power Co. IN
- 9.95%
6/22/2018 Duke Energy Carolina, LLC NC 9.90%
6/29/2018 Hawaii Electric Light Co., Inc. HI 9.50%
9.74%
Source:
-- "---- - -- - - -. - "" ~
Major ~ate C~e D_ectsion:_ Jan~: 11:!'1~ 2_0J8_; S&_~ <J!obal Market Intelligenc:e; July 17, 2018; p.10 (El'tctric Utility Decisions)
Removed decisions involving:
J?j~tribution only electric decisio~
Limited issue riders 10 11 Q..
- Please discuss how Staff arrived at the 9.30% ROE for the ERSP.
14 RRA Regulatory Focus Major Rate Case Decisions: January- June 2018; S&P Global Market Intelligence; July 17, 2018;p. JO. .
14
Direct Testimony of Adam H. Gatewood Docket No. l 8-KCPE-480-RTS 1 A. Staff was searching for a productive and fair settlement position for the 18-095 Merger, 2 which led Staff to consider a rate moratorium and a sharing mechanism of earnings above 3 an allowed return. Thus, it was necessary for Staff to perform a fresh and thorough analysis 4 of capital costs to determine the appropriate threshold for measuring earnings. At that time, 5 we were also aware that both KCP&L and Westar would be filing rate cases in 2018 and 6 the two utilities expressed a need to have some level of certainty regarding the cost of 7 equity recommendations in their upcoming rate cases, especially if they were going to 8 commit to an extended rate moratorium or an earnings sharing plan. For that reason, parties 9 agreed that the negotiated ROE applied in the ERSP would also become their 10 recommendation to use in setting the revenue requirements in the 2018 rate cases.
- 11 As I discussed in my 18-095 testimony, 15 my cost of capital analysis was developed in a 12 manner using conventions identical to those applied in rate cases. The results of my 13 analysis indicated that 9.30% was within a reasonable range for the ERSP. I also found 14 that capital costs were similar to those observed during Westar's and KCP&L's last rate 15 cases, which occurred in 2015. The Commission set KCP&L's ROE at 9.30% and adopted 16 a settlement in which Westar's ROE was about 9.35%. Thus, the cost of capital analysis 17 provided Staff with the positfon that Westar's and KCP&L's ROE could remain in place
- 18 from thei~ last rate cases to be used for the ERSP and setting rates in their 2018 rate cases.
19 Q.
- If the parties to the 18-095 S&A agreed to support a 9.30% ROE in this Docket, why 20 did you perform a new* cost of capital study?
.21 A. I did this to provide the Commission with a comprehensive record on which to base its 15 Testimony of Adam H. Gatewood, 18-KCPE-095-MER filed January 29, 2018; p. 33.
15
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 decision and to establish facts that demonstrate an ROE of 9.30% is a just and reasonable 2 return to use in determining KCP&L's revenue requirement. The signatories to the 18-095 3 S&A are aware that we cannot make a decision for the Commission. Ultimately, it is the 4 Commission that has to review the evidence and decide if 9.30% is a just and reasonable 5 return for setting KCP&L's revenue requirement. The legal standards that I discuss later 6 still apply to the Commission's decision, regardless of the fact that several parties have 7 reached an agreement on this issue amongst themselves.
8 Q. How much time has elapsed since you prepared the analysis for the 18-095 Docket?
9 A. About nine months. The time period of the capital market data I used in the 18-095 analysis 10 was January 1, 201 7, through December 31, 2017, and Staff filed its testimony on January 11 29, 2018. For my analysis in this Docket, I relied on financial data gathered from July 6, 12 2017, through July 3, 2018. In developing our position in the 18-095 Docket, Staff was 13 cognizant of the timing of both of these rate filings. Since the timing of the merger docket 14 and the two upcoming rate cases were relatively close together, Staff was comfortable with 15 connecting the three cases while recognizing our responsibility to prove the 9.3% ROE 16 included in the 18-095 Docket is reasonable for both the ERSP and the following rate cases.
17 Q. Have capital costs for electric utilities changed significantly over this time span?
18 A. No. Comparing the results of my analyses performed for the 18--095,18-328, and this 19 Docket demonstrates that capital costs to electric utilities have not changed significantly.
20 The following table summarizes the results from the analysis performed for each docket.
21 In essence, this table condenses results from three capital cost studies performed over three 16
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 over-lapping tim~ periods that cover a total of nineteen months from January 1, 2017, 2 through July 3, 2018.
Comparison of Staff ReC(_)f!!l_ll~!1~:la!~~11s ~c_ross 18-KCPE-095-MER Related Dockets Interest Rates Observed for Risk Premium Calculations
_30_¥<<;_~- _ Util_ityB_o~~ . ___ Mo_o_d)"s _ Bond Treasury Bond A/A Baa/BBB Corporate Baa YfM* '18-095 2.97% 4.13% 4.52% 4.58%, 4.24%'18-328 2.90% 3.97% 4.28% 4.39%1 3.85%'18-480 2.94% 4.01% 4.32% 4.44%1 4.12%i Risk Premiums Over Fixed-Income Interest Rates 30 Year Utility B~nds _ _ ~o_ody's _ Bond Treasury Bond A/A Baa/BBB Corporate Baa YfM*
18-095 6.33% 5.17% 4.78% 4.72%; 5.06%;18-328 6.40% 5.33% 5.02% 4.91%' 5.45o/o:
18-480 6.36% 5.29% 4.98% 4.86%1 5.18%,
Cost of Equity Models
- Discounted
- - - - - ___ Internal Rate __ __ Capital Asset Pr1cingModels ___ .
Cash-Flow of Return Historic Data Forecasted Data :
18-095 8.09% 7.81% 9.29% 6.30%_!18-328 8.22% 8.02% 9.00o/o 6.09%'18-480 8.28% 8.28% 9.00% 6.09%*
- Yield to maturities reported on Great Plains and Westar Energy bonds for 18-KCPE-095-MER; Westar Energy bonds_ for 18-WSEE:328-RTS; and Great Plains Energy bonds for 18-KCPE-480-RTS.
Data period for each docket:
l 8-KCPE-095-MER Janua_ry 2911 - r:>ec~rnber 2017 1~:WS!':E-328-RTS May 2017 - April 2018
)~-K~E-480-RTS May 2017 - J~ ~018 Sources: Gatewood Direct, 18-KC::PE-095-~R; file~ Janllfil)' 29, 2018; pp. 16, 22.
Gatewood Direct, 18.KCPE328-RTS; filed June 11, 2018; pp. 22,26.
3 4 This table summarize~ substantial evidence that the current cost of capital has remained 5 similar to the range_measured in Staffs the 18-095 S&A. This is true for both the cost of 6 equity of the proxy group of electric utilities as well as broader rpeasures of interest rates 7 on U.S. -Government 30 Year Bonds, corporate bonds, and public utility bonds. Staff 8 believes this comparison of capital costs across the three dockets supports the use of a 9 9.30% return on equity agreed to in the 18-095 S&A to set KCP&L's revenue requirement 10 in this Docket.
17
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS 1 Q. Please summarize the results of your cost of equity analysis performed for this 2 Docket.
3 A. The following table summarizes the cost of equity estimates from my study in this Docket; 4 the details of each financial model appears later in my testimony. I relied on a discounted 5 cash flow (DCF) model, a variation of the DCF model known as an internal rate of return 6 (IRR) analysis, and the caphal asset pricing model (CAPM). These are the models I 7 typically use to estimate a utility's required return on equity. The results in this table are
- 8. based on the capital markets using data from July 3, 2017, through July 2, 2018.
__ Sum~ary of Staffs Cost of Equity Estimates _
18-KCPE-480-RTS Discounted Cash Flow Analyses _
' Mean , Low High
'Two-Stage Growth DCF Model: 8-28% 7.84%. 8.71%
_Based on the Average of Short-Term Growth
' Forecasts & Long-Term nGDP Forecasts _
Internal Rate ofReturn-Multi-Stage DCF Analysis: 8.28% 7.39% 9-47%
- using Short-Term Growth EPS Growth &
Long-Term nGDP Forecast
- Based on Historical_ Return Data; gathered from. 9.00% 7.83% 10.93%
, 192§ - 2017; Repo~d ~y SBBI; D_uff ~ Phelps 0
'i3ased on-ForecasiecfReturn Data Pub! ishedby- . 6.09% 5-43% 7.17%
- lf. M~rga_!l ~~Se! ~a~!l_e~_n! (~_1..8 edip~n)_
9 10 Q. For a point of comparison, please summarize return on equity decisions by this 11 Commission and Commissions across the country?
12 A. The first table contains allowed return on equity decisions made by this Commission in 13 litigated rate cases. As a point of reference to the prevailing capital markets at that time, I 18
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS
\
1 included the yield on the Baa rated corporate bonds as of the month of the Commission's 2 decision.
i 1-------------- Commission Determined Allowed RO Es -- Kansas Utilities --- --- ! --- -j-
r---- ---- r=::==- : ------1--------r-
- F~-~-~=Company- -_ ~- ~~F---=- Docket -~-. j- OrderD~-Rei~;edT- 0 ~~~d -rB~i~l~nd-i-
- !Kansas City Power & Light____ ~_!J5-KCPE-116-RTS _l__~ 0/2015 10.30% I ___ ___2:30% ~ ___4.86%J_
,AtmosEnergyCorp. ,14-ATMG-320-RTS _, 9/4/2014 10.53%[ 9.10% 1 4.89%!
-;Kansas City Power & - Light -c 12-KCPE-764-RTS- --j"- 12/13/2012 --10.40%* --* -- 9.50%i---4.80%f
- --- \_. _____________ - -- -- -- -----t --- - ______ ,. _ ___ - - - - 1 KansasCityPower&Light :10-KCPE-415-RTS 11/22/2010 10.75%[ 10.00%i 5.56%J
~--::::~:::tf____
---:~--;;aass~i~eCo.
1it~~1~ttir 1193)05:ff*---- --
1
~~~~~6~r ---~1~~~f ii:6~~--- - l!~~-
4/15/19961-- -- *12.00%1 w..sw.1-- --- 7.77%1 1
-* i _____ .l_ ____ ____J_ ____ -~- ------ ___ )__________ :_
- Sources: SNURRA; Federal Reserve Banlc of St. Louis, FRED
---rI --- -- --T: --r!
3 4 The following chart is broader in both ,the time period and reporting scope. It indicates the 5 median return on equity granted in fully-litigate~ rate cases across the nation .from 1980 6 through June.of 2018. As a point ofreference to the prevailing capital markets, I included 7 the average yield to maturity of Baa corporate bonds.
Long-Term View of Electric Utility ROE and Baa Corporate Bond Yields 17.00%
16.50%
16.00% .,
is.so% A AA: i. -
15.00% a 1-t..50% -
- 1~i:.:
- 13.00%
- -*- e ~_:----~----
- -- .......... .t. - -
12.50% - * --- ..... - --
12.00% -,A- ....
- ~i::
10.so% ***- -
--- *::~-...~... - ............j;...*
- i * -- _---
... ... -... A-_A:-.. ---- --- -- -- ---
10.00% --- ------- ---- --.- -- - - - - - -- ...........- -...- -...-
9.50% - - -- -- --- - --- - -----*-*-
9.00% *-
8.50% -- - - * **-- - -.-
8.00% - .. ** - - e e .- - -- *-* - --
Hm* -~~--:-~---~- -~~~-- ~--~----~-:---~--~--- ~----;~~:~~:;-~--~~:- ___ ~----
5.50% * - *- - - -- --- - ---
~:~g~: -_-___ -_---_---_ ----_----- _______ --_-___ --- -- _-- ------__ --------**~*~*
4.00%,
3.50%
itiilli~lfiil!i~i~ii§s§8388~§§~=~~3~
NijN~ijij~NNNNgNgggN ~~~
NN, Allledian ROE eBaa Corporate Yield 8
9 The next chart highlights a shorter time period, the last four years from early 2014 through 19
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 June of 2018. Compared to the decline seen in the chart of the long-term changes, the past 2 four years show a plateau in the median allowed return granted.
Electric Utility ROE and Baa Corporate Bond Yields 11.00%
10.50% -- . --- -- --**--* - - - - - - - - - - - - - - - -
10.00% ;a A A A A A 9.50% A.. J.- . --A- -- £ ___ - ~--- - A- --* £_ A- - A - . A. -
9.00%
8.50%
8.00%
7.50%
7.00'Yo 6.50%
6.00%
5.50% - -- -~----- -- -~-~ ~ .--.*-*-*-* ~- -
- *-** *-* :;._-.-i ~~----*-*-* ~-. ---------* ... --- -. ; .-** -~--:;--..* ~ ;_;~~-.-.* ***-. ~ ** **
4.00%
3.50%
eBaa Co!J)Orate Yield .I.Median ROE 3
4 Q.. How does Staff's recommendation compare to the returns available on other 5 investments?
6 A. The following table shows that Staffs recommendation of a 9 .3 0% return on equity allows 7 investors a risk premium over less risky debt investments. These types of income 8 producing securities are viewed as alternatives to investments to utility stocks because, like 9 utility stocks, bonds offer stable valuations and higher current income relative to the equity 10 market. Risk premiums vary over time and across market conditions; thus, there is not a 11 benchmark risk premium or formula that sets a reasonable return on equity at a given 12 interest rate. Nor has the Commission set a definitive spread over bond yields, but the 13 Commission's Order in 15-KCPE-115-RTS (15-116) noted that its decision allowed 20
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 KCP&L a risk premium of 525 basis points over the yield on its long-term debt. 16 In that 2 Docket, Staff argued that a 525 basis point risk premium over the bond yield was 3 reasonable as it offered stockholders a higher re.tl!m than available on the lower risk debt 4 securities. The Commission agreed and applied Staff's risk premium to amve at an 5 allowed return for KCP&L.
I I I I I KCC Staff's Risk Premium Over Fixed Income Yields Based on a 9.30% Return on Equity Fixed Income Yield Observations July 2017 tbrou~h June 2018 18-KCPE-480-RTS 30 Year (1) Utility Bonds (2) Moody's (3) KCP&L(4)
Treasurv Bond AJA Baa/BBB Coroorate Baa BondsYTM JtD1-l8 3.03% 4.23% 4.58% 4.83% 4.33%
May-18 3.14% 4.27% 4.62% 4.83% 4.37%
Apr-18 3.07% 4.17% 4.50% 4.71% 4.29%
Mar-18 3.09% 4.12% 4.45% 4.65%. 4.22%*
Feb-18 3.13% 4._14~_ 4.42% 4.47% 4.21%
Jan-18 2.88% 3_&1~. 4.14_~ 4.25% tJ~%.
Dec-17 2.77% 3.80% 4.08% 4.~~~;* 3.94%
Nov-17 2.81% 3.84% 4.11% 4.06% 4.00%
Oct-17 2.88% 3.92% 4.21% 4.32% 4.03%
Sep-17 2.78% t~~- 4.19% 4.30% 3.95%
Aug-17 2.80% 3.87"/o 4.20% 4.32% 3.99%
Jul-17 2.88% 3.99% 4.31% 4.40% 4.13%
Average-: 2.94% 4.01% 4.32% 4.44% 4.12%
Risk Premiums Over Fixed Income Securities KCC Staffs Recommended ROE 9.30%
I Average Yield on30 Year Treasury Bond 2.94%
Eauity RiskPrellaumOverthe 30-YearTreaswy Bond Yield 6.36%
KCC Staffs Reco~nded _R.ClE 9.30%
Average Yield on "A" Rated Utility Bonds 4.01%
Equity RiskPrellaumOver "A" Utility Bond Yield 5.29%
KCC Staffs Recommended ROE 9.30%
Average Yield on "BBB/Baa" Rated Utility Bonds
- 4.32%
Equity Risk Premium Over "Baa/BBB" Utility Bond Yield 4.98%
I I KCC Staffs Recommended ROE 9.30%
Average Yield on "BBB/Baa" Rated Utility Bonds 4.44%
E(IWty Risk Premium Over Moody's "Baa/BBB" Coroorate Bond Yield 4.86%
KCC Staffs Recommended ROE 9.30%
_,',vs!age Yl!oltto Maturityo_nK(2@B_o_!]ds 4.12%
E(ll!i_ty J!.!sk P_i.:e.!fill_l!l ov~r Yiel~ on~~~ Bo[!ds 5.18%
I) Board of GoYemors of the Federal Resen*e System (US). 30-Ycar Treasury Constant MaturitJ*
(Federal Reserve Bank of SI. Louis; Release H.15) I I
- 2) Yield on A and BBB/Baa Rated Public Utilty Bonds 25 to 30 Maturity I Renorted weeklv in Value-Line Investment Survev, Selection & Oninion Section.
- 3) Yield on Moody's Baa Corporate Bonds reported at FRED (Federal Rcsen*c Bank of St. Louis Electronic Data)
- 4) Average yield to maturitv reported by FINRA on KCP&L 6.05%, 2035; KCP&L 5.30%, 2041; I KCP&L 4.20%, 2047, and KCP&L 4.20%. 2048 I I I 6 I I I I 7 Standards for a Just & Reasonable Rate of Return 16 Order issued on KCP&L's Application on Rate Change; 15-KCPE-116-RTS; September 10, 2015; para. 34.
21
Direct Testimony of Adam H. Gatewood Docket No. l 8-KCPE-480-RTS 1 Q. What is the role of rate of return in setting a revenue requirement for public utilities?
2 A. .The standards for setting a just and reasonable rate of return require that, to be reasonable, 3 the allowed return must reflect the risks associated with an equity investment in the utility.
4 For the allowed return to be in that reasonable range, it must compensate for those added 5 risks while capturing a fair proportion of benefits for consumers. The terms of the 18-095 6 S&A, although beneficial to all stake-holders, possess several risks to shareholders not seen 7
- in a traditional rate case and the Commission must consider these risks.
8 The allowed ROE is best described as the forward-looking discount rate that is necessary 9 to induce 'equity investors to commit their capital to the enterprise. The courts have 10 articulated standards for regulatory agencies to use to gauge the fairness and 11 reasonableness of an allowed ROE. Financial analysts and policy-makers rely on the 12 courts' decisions as a guide in estimating the appropriate cost of capital. The opinions do 13 not articulate precisely how to estimate or model a reasonable cost of capital. Instead, the 14 decisions provide critical questions for policy makers and analysts to consider in 15 . determining a reasonable return for a regulated utility.
16 In general, United States Supreme Court decisions state that returns granted to regulated 17 public utilities should: 1) be commensurate with returns on investments of similar risk; 2) 18 be sufficient to assure the financial integrity of the utility under efficient economic 19 management; and 3) change over time with changes in the money market and business 20 conditions. 17 An important take-away from these decisions is that the Supreme Court of 17 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).
22
Direct Testimony of Adam.H. Gatewood Docket No. 18-KCPE-480-RTS 1 the United States has afforded regulatory agencies a significant amount of latitude in 2 establishing an appropriate ROR and ROE for a utility. The Kansas Supreme Court has 3 recognized and follows this body of law. 18 This Commission has noted this fact in Orders 4 issued in previous dockets. 19 5 Q. Discuss how financial analysts apply the standards established by the Court.
6 A. For an allowed ROE to meet the legal standards, the return should be as specific as possible 7 to the utility in question. There are several court cases that, as a gr~_up, are viewed as the 8 keystone to measuring the adequacy of a utility's allowed return. The earliest of these 9 decisions go back to an era when it was not only the "rate of return" at issue but also the 10 fundamental measurement of the investment in the utility enterprise, commonly referred to 11 as rate base. This is less of an issue today as regulators, utility management, and investors 12 readily accept actual historic-depreciated value as the measure of investment to estimate 13 the value of a utility's rate base (as opposed to reproduction cost or market value). The 14 Court's decision in Bluefield addressed both rate base and ROR. 20 Treatises on rate of 15 return for public utilities, such as The Cost of Capital - A Practitioner's Guide, agree that 16 Bluefield lays out the four standard~ for a fair return:
17
- 1) Comparable Earnings - a utility is entitled to a return similar to that being earned by 18 other enterprises with similar risks, but not as high as those earned by highly profitable 19 or speculative ventures; 20 - 2) Financial Integrity- a utility is entitled to a return level reasonably sufficient to assure 21 financial soundness; 18 Kansas Gas & Elec. Co. v. State Corp. Comm'n, 239 Kan. 483,491, 720 P. 2d 1063, 1072 (1986).
19 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.
20 Bluefield Water Works & Improvement Co. v. Pub. Svc. Comm'n of West Virginia, 262 U.S. 679, 692-3 (1923).
23
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 3) Capital Attraction .:... a utility is entitled to a return -sufficient to support its credit and 2 raise capital; and 3 4) Changing Level of Returns - a fair return can change along with economic conditions 4 and capital markets. 21 5 As a financial analyst formulating rate of return analyses for our state commission, I take 6 from Bluefield that the Court requires a rate order that_ allows a utility an opportunity to 7 earn a return consistent with the utility's risk profile and consistent with observations in 8 the capital markets. The Court's decision in Hope, 22 like that in Bluefield, dealt with both 9 valuation of rate base, as well as rate of return on that rate base. With respect to the rate of 10 return, the Court in Hope affirmed the four standards set out in Bluefield.
11 KCC Proxy Group 12 Q. How did you select a proxy group for your cost of equity analysis?
13 A. To narrow the universe of potential proxy companies, I used the following selection 14 criteria:
15
- Has publicly traded common stock 16
- Is an electric utility followed by Value-Line Investment Survey 17
- No recent spin-offs, mergers or distressed assets 21 The Cost ofCapital*-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.
22 Federal Power Comm 'n. v. Hope Natural Gas ca:, 320 U.S. 591, 603 (1944). "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.' Btit 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 corresponding 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 arrived at. For we are of the view that the end result in this case cannot be condemned under the Act as_ unjust and unreasonable from the investor or company viewpoint.
24
. Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1
- Exhibits stable dividends-No recent dividend cuts 2
- Possesses an investment grade bond rating between A3/A~ and Baa2/BBB 3
- Earns at least 70% of its annual revenues by providing regulated electric utility 4 services 5 These parameters are identical to those that I used in the 18-095 Docket and 18-328 Docket 6 and support using the same group of electric utility companies as a proxy group in this 7 analysis as was used in those two previous dockets. Both before and after the merger, 8 Westar and KCP&L possess nearly identical risk profiles, thus it is expected that we would 9 use the same proxy group for both utilities.
10 Stock-price data is critical to a cost of equity analysis as that price data encapsulates the 11 market partic~pants' valuation of the company. Selecting companies that investment 12 research companies like Value-Line categorize as electric utilities focuses the analysis on 13 companies facing similar types of business risks and opportunities and ensures that 14 publically available financial data is available. As a starting point, this parameter is 15 . important as it assures us the companies generally derive their earnings in electric utility 16 industry. The following table contains all of the electric utilities followed by Value-Line.
17 The bold and boxed cells indicate the primary reason for rejection from the proxy group.
25
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS I 2 3 4 5 6 7 8 9 10 No Dividends 2017 Value-Line: Electric Utilities ***Bond Rating*** Announced No Planned 2017 Electric Operations Company Name Moody's S&P Merger Reductions History %Rev %Assets*
Allele Inc ALE A3 BBB+ Yes X X X 74.9%
yes
- Alliant Energy Corp Ameren Corp LNT AEE Baal Baal A-BBB+ ¥~
X
~
X X ,,
X 85.6%
86.0%
82.6%
85.0%
American Electric Power Company Inc AEP Baal A- Yes *X X 94.1%
QllQl:IJQIW) iAii. AGR Baal BBB+
Yes X
X
-* X X
~~--*
81.0% 85.7%
~ AVA *Hyjro-One Merger* _
lllaol, Uills Go,p BKH *Selling oil & gas assets*
-- 31.7% 45.4%
CeateFl!eiRt SeeFffii1 Im; CNP Baal A- Yes X X X CHi liRBFre Gerp CMS Baal BBB+ Yes X X X 67.5% 60.3%
Consolidated Edison Inc . ED A3 A- Y_es X X X 76.6% 73.3%
DamiRiaA S1ier~ D *AcquiriJ:tg SCANA*
l'J:rJ; ll**'l!l' G*'"l'*"l' DTE Baal BBB+ Yes X X X 40.5% 62.7%
Duke Energy Corp New DUK Baal A* ye~ X ~- X 90.5% 86.6%
Edison International Ell( AJ BBB+ Yes X X X 99.0% 89.9%
El Paso Electric Co EE Baal BBB Yes X X X 100.0%
SRteEgy GeFp ETR Baa2 BBB+ Yes Closing 4 non-reg nuclear plants E 8F581:iF68 Bll8Ffil ES Baal A+ SPLT X X X 71.5% 53.0%
~ EXC Baa2 BBB Yes X X X 44.4%
liiFstl!AeFffi GeFp FE Baal BBB* NO Sub. Bankruptcy/elim. non-reg X X 69.4% 64.2%
l'eRis,IR& FTS.TO Baa3 A- X X 54.0%
Qieat l!laiR& liA1iFm1 In* GXP Baa2 BBB+ Yes Westar l:lai11aiiaR ElesGie lnd11S&ie& IA6 HE BBB- NO X X X 88.0% 47.0%
IDACORP Inc IDA Baal BBB Yes X X X 99.0% 99.0%
I IGll ll"l!l' I** MGEE Al AA- NO X X X 73.5% 56.2%
We!iiteFa EneFre,1 Ins NEE Baal A- Yes X X X 69.0% 51.4%
NorthWestern Corporation NWE Baal BBB Yes X X X 79.3% 80.1%
OGE Energy Corp OGE AJ A- Yes X X X 100.0%
QtteF +ail GeFp OTTR Baa2 BBB Yes X X X 51.0% 84.3%
Paeiffe Gas an!I EleeGia Gempa~ PCG Baal BBB+ Yes X Suspended Pinnacle West Capital Corp PNW A3 A- Yes X X X 99.0% 98.0%
l!NM Resgw:ees Im: PNM Baa3 BBB+ SPLIT X X X 100.0%
Portland General Electric Company POR AJ BBB Yes X X X 100.0%
l!P:b GeFp8Fatiea PPL Baa2 A- Yes Forex risk X X 71.9% 59.2%
PYhlis SeF iee EnleFpFise Gl:eYf.1 IR6 PEG Baal BBB+ Yes X X X 68.1% 66.9%
SG OiN Oi GeFpeFatiea
- SCG Construction issues/ACQ Sem1na Energy SRE Baal BBB+ Yes Onocor acquisition X X 39.4% 35.7%
~ so Baa2 A- Yes Construction issues X X 73.0% 65.8%
lteeGenGeFp vvc A- Yes X X X 21.4% 29.1%
WEC Energy Group WEC A3 A- Yes X X X 60.0%
mes'-IF lineF~ IA6 WR Baal BBB+ Yes Great Plains 100.0%
Xcel Energy Inc XEL AJ A- Yes X X X 84.9%
- 1) Electric utilities followed by Value-Line Investment Survey (U.S. companies)
- 2) Ticker symbol
- 3) Moody's credit rating (LTR) data from S&P Global Market Intelligence
- 4) S&P credit rating (LTR) data from S&P Global Market Intelligence I
- 5) Within credit rating range of both rating agencies
- 6) No merger, acquistion, or sale of assets (Value.Line & S&P Global Market Intelligence)
- 7) No forecasted dividend reduction (Value-Line) x = no reduction
- 8) No dividend reduction in 2017 (Value-Line & S&P Global Market Intelligence) x = no forecasted reduction
- 9) Revenues from regulated electric operatiom-*% of total revenues (S&P Global Market Intelligence) 70% of Revenues from electric utility industry I 0) Assets ofregulated electric operations (S&P Global Market Intelligence) 1 2 I reviewed the potential proxy companies that were considered in the 18-WSEE-328-RTS 3 Docket. I found that the selection screens applied in the 18-328 analysis to be a reasonable 4 guide for selecting a proxy group for KCP&L in this Docket. Credit ratings shown in 5 columns three and four are the first screen applied to the population. The current ratings 6 forKCPL is Baal by Moody's and A- by S&P; these ratings are firmly in the mid-range 7 of the investment-grade ratings. The selection criteria uses a range that is one notch either 26
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 side ofKCPL's ratings which is a range of A3/A- to Baa2/BBB. 23 2 In column six, I listed any merger or acquisitions in process or any significant financial 3 issues that make it difficult to assess the utility's long-term earnings prospects. In this 4 criteria, I found there are several utilities involved in acquisitions. SCANA and Southern 5 Co. are excluded due to their construction problems with nuclear power plants; SCANA
\.
6 has also signed in acquisition plan with Dominion. I excluded utilities involved in
- 7. acquisitions and those with significant construction issues because both types of events 8 cause uncertainty around future earnings. I also excluded PPL Corp. due to its investments 9 overseas. *PPL reports that 30% of its revenues are subject to foreign exchange risk. This 10 is an atypical situation in the U.S. electric utility industry and a risk that is distinct from 11
- KCP&L. The filter in column six focuses the study on electric utilities with known 12 prospective earnings power.
Credit Rating Table
~_oody's_ S&P Aaa AM
. Aal AA+
"O o:I Aa2 Aa3 AA AA-
".= . Al A+
s."' A2 A3 A
A-
- i: Baal Baa2 Baa3 BBB+
BBB BBB-B_al ~B+
. Ba2 BB "O
o:I Ba3 BB-
"...=. Bl B2
--~
B+
8 s."' B3 8-Caal CCC+
-...-==
i:
o:I Caa2 Caa3
- _Q.<;:<;:
CCC-
- - - -cc Ca
...l C+
C 23 C D 27
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 Columns seven and eight are similar to column five in that these criteria would eliminate 2 firms that have or are forecasted to reduce annual dividends. In the public utility sectors 3 where management and boards strive for a record of stable dividend growth, a dividend 4 reduction signals major change in ongoing operations and is probably a sign that 5 managements cannot expect stable earnings growth in the foreseeable years. Such 6 candidates should not be in the proxy group for KCP&L because that situation is not 7 consistent with KCP&L's prospects. Pacific Gas & Electric is the only utility eliminated 8 with this criteria; it suspended its dividend payments in December of 2017.
9 The criteria in columns nine and ten attempt to ascertain whether providing regulated 10 electric utilities services is the primary business *of the company. I set the threshold for 11 revenues from electric utility service at 70% of total revenues. This is a subjective cutoff, 12 but it works for this analysis because meeting that threshold means that the company is 13 largely focused on, and earnings are derived from, providing regulated electric utility 14 services. The following table contains Staffs proxy group of 14 electric utilities for the 15 cost of equity and capital structure analyses.
28
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS 1 2 3 4 5 6 7 8 9 10 No Dividends 2017 Value-Line: Electric Utilities ***Bond Rating*** A1U1ounced No Planned 2017 Electric Operations Company Name Moody's S&P Me1"2er Reductions Historv %Rev %Assets*
Allele Inc AIE A3 BBB+ Yes X X X 74.9%
Alliant Energy Coro LNT Baal A- Yes X X X 85.6% 82.6%
Ameren Corp AEE Baal BBB+ Yes X X X 86.0% 85.0%
American Electric Power Company Inc AEP Baal A- Yes X X X 86.7% 94.1%
Consolidated Edison Inc ED A3 A- Yes X X X 76.6% 73.3%
Duke Energy Corp New DUK Baal A- Yes X X X 90.5% 86.6%
Edison International EIX A3 BBB+ Yes X X X 99.0% 89.9%
El Paso Electric Co EE Baal BBB Yes X X X 100.0%
IDACORP Inc IDA Baal BBB Yes X X X 99.0% 99.0%
NorthWestern Corporation NWE Baal BBB Yes X X X 79.3% 80.1%
OGE Energy Coro OGE A3 A- Yes X X X 100.0%
Pinnacle West Caoital Coro PNW A3 A- Yes X X X 99.0% 98.0%
Portland General Electric Company POR A3 BBB Yes X X X 100.0%
Xcel Energy Inc XEL A3 A- Yes X X X 84.9%
l) Electric utilities followed by Value-Line Investment Survey (U.S. companies)
- 2) Ticker symbol
- 3) Moody's credit rating (LTR) data from S&P Global Market*Intelligence
- 4) S&P credit ratirig (LTR) data from S&P Global Market Intelligence
- 5) Within credit rati~ge of both rating agencies
- 6) No merger, acquistion, or sale of assets (Value-Line & S&P Global Market Intelligence)
- 7) No forecasted dividend reduction (Value-Line)
- 8) No dividend reduction in 2017 (Value-Line & S&P Global Market Intelligence)
- 9) Revenues from regulated electric operations 70% of total revenues (S&P Global Market Intelligence)
I 0) Assets ofregulated electric operations (S&P Global Market Intelligence)
I 2 Q. Have bond ratings for Westar or KCP&L changed since the cost of equity studies in 3 the 18-095 and 18-328 Dockets?
4 A. Yes, with the close of the merger of Westar and Great' Plains Energy, Standard & Poor's 5 raised its rating of Great Plains Energy and each of its subsidiaries one notch from BBB+.
6 toA-. Moody's did not change its ratings of any of the companies. Because this was a 7 one-notch change and by just one of the two rating agencies, I did not alter the proxy 8 company selection criteria from that used in the previous two dockets.
29
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS Bond Ratings of Evergy, Inc.
& Kansas Jurisdictional Subsidiaries Pre-Merger Rating/ Post-Merger Bond Rating Standard
&Poors' Moody's Evergy, Inc./Great Plains Energy BBB+/ A- Baa2/Baa2 Kansas City Power & Light BBB+/ A- Baal/ Baal W~s~r E_f!~~gy_ _ BBB+/ A- Baal/ Baal Kansas Gas & Electric BBB+/ A- Baal/ Baal Source: S&P Global Market Intelligence 1
2 Return on Equity Analysis 3 Q. How did you perform the cost of equity analysis?
4 A. I am using discounted cash flow models and capital asset pricing models; identical to the 5 methods used in recent rate cases: the 18-095 Docket and 18-328 Docket to establish the 6 9.30% threshold for the ERSP.
7 Q. Does the DCF model meet the legal standards discussed earlier in your testimony?
8 A. Yes, a cost of equity estimate derived from the DCF model meets the legal standards 9 discussed above if the model incorporates current information from the capital markets via 10 current stock prices and accurate data that investors use to establish their discount rate.
11 This market-based information ensures the cost of equity estimates evaluate investors' 12 required rate of return or discount rate that reflects the current economic environment.
13 The DCF model is a valuation model used by investors to value different types of 14 investments such as real estate, bonds, and equity securities. The DCF model is a useful 15 tool to value any investment that involves regular, periodic cash flows. The notion of 30
Direct Testimony of Adam H. Gatewood Docket No. l 8-KCPE-480-RTS 1 discounting a future receipt of cash back to the present so as to place a price or value on an 2 *
- investment goes back centuries. 24 The premise of the DCF model in the valuation of
\
3 common stock is that investors determine the value of a company's common stock by 4 discounting its future dividend payments back to the present. The cornerstone of the DCF 5 model is the process of discounting those future cash flows back to the present at the 6 investors' required return. An investor's required rate of return is risk-sensitive and 7 sensitive to the returns available on investments of comparable risk throughout the global 8 capital markets. In other words, as the risk of the investment increases, so will the 9 investors' required return. A higher required rate of return decreases the present value 9f 10 the stream of dividends that equates to the price of the stock So, all other variables being 11 equal, investors price the riskier of two common stocks lower because the cash flows or 12 dividends are discounted back to the present at a higher rate.
l3 The form of the DCF model that regulatory agencies are accustomed to seeing is often 14 referred to as the Gordon Growth Model, which is a model that values the security at the 15 present value of a stream of cash flows (dividends) growing at a constant rate into 16 perpetuity. The basic form of this DCF equation is:
D0 (1 + g) 17 Po= -(K_e___ g_)
18 Where:*
19 Po= the value of the common stock or asset 24 The formal presentation of the DCF model as we use it today dates back to the 1930's in Irving Fisher's book: The Theory of Interest and John Burr Williams' 1938 text: The Theory of Investment Value. These two authors expressed the DCF model in modem economic terms.
31
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-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 Or 5 Stock Price= Annual Dividend/ (Req'd Rate of Return -Dividend Growth Rate) 6 This is the form of the equation commonly found in texts regarding finance, investments, 7 and asset valuation. Such texts are inclusive of both theory and practical application.
8 Regulatory agencies responsible for setting rates and revenue requirements want to know 9 the investors' required rate of return or Ke in the equation. So, we solve the equation for 10 that variable. The equation below shows the algebraic isolation of the investors' required 11 rate of return. By isolating investors' required rate of return in the equation, we can
- 12 estimate it by knowing the stock's dividend yield and the annual dividend growth rate 13 expected by investors. That form of the equation is:
D0 (1 + g) 14 Ke= Po +g 15 This equation is frequently written out as:
16 Req'd Rate of Return= (Dividend/Current Stock Price)+ Dividend Growth Rate 17 or 18 Req'd Rate of Return= Dividend Yield+ Dividend Growth Rate 19 20 Or as commonly abbreviated by regulatory agencies 32
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 Ke=y+ g 2 Where: y = Dividend Yield 3 g = Expected Dividend Growth 4 Through a handful of inputs, the DCF model distills down to an equation, a complex 5 ' proc.ess performed by investors to arrive at a discount rate and valuation of the security.
6 As with any equation that attempts to model behavior, there are a host of assumptions that 7 come along with it. Those assumptions are:
8
- Ke corresponds only to the specific stream of future dividends, rather than earnings, 9 and that constitutes the source of value.
10
- The discount rate (Ke) must exceed the growth rate (g).
"11
- The constant growth rate will continue for an indefinite future.
12
- Investqrs require the same discount rate (Ke) each year.
13
- There is no external financing.
14 Q. Why is it reasonable to accept thes.e assumptions?
15 A. The DCF model is attempting to emulate investors' behavior; distilling human b~havior 16 into a handful of inputs demands simplifying assumptions. The question becomes whether 17 the assumptions are so contrary to investors' behavior in the real-world that the model 18 output becomes meaningless or illogical. There is no strong evidence that leads me to 19 believe the assumptions of the DCF model are contrary to investor behavior.* Moreover, 20 there are methods I use to evaluate whether an output falls outside of the realm of reality.
21 For example, the output can be compared with the returns available on other investments 22 such as long-term corporate bonds. There were no observations eliminated using this 33
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS.
1 screen. 25 2 Discounted Cash Flow Model 3 Q. 'How did you calculate the dividend yield (y) component of the DCF model?
4 A. The* dividend yield (y) is the easier of the two components to measure as it is easily 5 *observable in daily stock price reports. It is calculated by dividing the stock's annual 6 dividend payment per share by its market price per share.
7 Q.
- What is the source of the dividend information?
8 A. Historic and current dividend information is easily obtained from public sources or 9 subscription services such as Value-Line. The DCF model requires a forward-looking dividend payment which is often the current year's dividend payment increased by the 11 forecasted grow:th rate for next year. In lieu of forecasting, I obtained the 2019 forecasted 12 dividend per share information from Value-Line Investment Survey. The Value-Line 13 reports for each of the proxy companies are attached as Schedule AHG-3. I obtained the 14 stock prices for the dividend yields from YahooFinance. For this analysis, I used weekly 15 stock price observations taken from July 2, 2017, through July 3, 2018. The stock prices 16 for each of the proxy companies appears on Schedule AHG-4. My DCF analysis 17 -incorporates a dividend yield based on forecasted 2019 dividend payments.
25 Staff applies this screen using the interest rates of Baa Utility Bonds and the yields on utility specific debt shown in the Risk Premium Table. Staff adds 100 basis points to these yields as a minimum risk premium test. Cost of equity observations below this level are eliminated from the average. FERC proceedings apply a similar test for outliers.
34
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS Staff Proxy Group Dividend Yields Based on Prices from July 2, 2017 through July 3, 2018 18-KCPE-480-RTS I 2 3 4 5 6 7 DPS Stock Prices Dividend Yield 2019 Min Max Mid-Point Mean Min Max Allete Inc ALE. $ 2.34 $ 66.64 $ 81.24 $ 73.94 $74.78 2.88% 3.51%
Alliant Energy Corp LNT $ 1.42 $ 36.84 $ 45.55 $ 41.19 $41.56 3.12% 3.85%
Ameren Corp AEE $ 1.94 $ 51.89 $ 64.89 $ 58.39 $ 58.17 2.99% 3.74%
American Electric Power Co. AEP $ 2.63 $ 62.71 $ 78.07 $ 70.39 $70.22 3.37% 4.19%
Consolidated )3dison Inc ED
. - *- $ 2.96 $. IJ-~2- $- . 89.70 $ 80.41 $ 80.75 3.30% 4.16%
Duke Energy Corp New DUK
$ *:i:so $. ?_L96 $ 91.80. _$ 81.88__ $81.78 _ 4.14%
5.28%
Edison International EIX $ 2.57 ~- ~?,6°? $ 83.38 ; $ ---*--
70.50 $ 69.71 3.08% 4.46%
El Paso Electric Co EE
$ 1.52
.. --- $ 48.05 $ 61.15 $ 54.60 $54.44 2.49% 3.16%
IDACORP Inc IDA $ 2.56 $ 79.59 $ 100.04 $ 89.81 $ 89.08 2.56% 3.22%
NorthWestern Corp_1?ration NWE $ 2.30 $ 50.01 $ 64.47; ~ 57.24 $_56.88 3.57% 4.60%
OGE Energy_f~--- OGE
$ 1.54 $ 29.59 $ 37.32 $ 33.46 $34.06 4.13% 5.20%
Pinnacle West Capital Corp_ PNW
$ 3.02 $ 73.41 $ 92.48 $ 82.95 $ 83.23 3.27% 4)J~
Portland General Electric Co. POR
* ! 1.50 $_}~Q2 $ 50.11 $.. 44.57 ~~~:27 .. 2.99%
3.84%
Xcel Energy Inc XEL $ 1.60 $ 41.51 $ 52.22 $ 46.86 $46.77 3.06% 3.85%
Range: 2.49%
- 5.28%
!) Dividends per Share for 2019 Forecasteiby Value-Line lnves~nt Survey
- 2) Minimum 12 month price observed from July 2, 2017 through July 3, 20-1!-
- I) Maximum 12 month price observed from July 2, 2017 thr~gh July_3, 2018
~~~- -~_::==-~--
~~=
_ ~ Mid-point is the average of minimum price and maximum price _ _ .. ___ ... _ _ _ _ ___ _
- ~ Mean price for the time period ofJuly 2, 2017 through Jul_y 3, 2018 ~eek!Y. <!~~ervations)_ ____ _ _ _ _
_ 6) Minimum dividend yield available from time_p~riod
>- 7) Maximum dividend yield availabl~ from time period 1
2 Forecasted Growth Rates for the DCF Model 3 Q. Please discuss the importance of the second component, the growth rate '(g), in the 4 DCF equation.
5 A. The "g" represents the anticipated annual growth rate in cash-flows that investors expect 6 to receive through dividends from the stock. This is a challenging and contentious issue in 7 a DCF analysis for two reasons. First, it is a key element in the DCF model or any form 8 of a discounted cash flow analysis because the growth rate has a one-for-one effect on the 9 required return produced by the model. All other factors being equal, a higher growth rate 10 results in an equally higher return on equity for the utility. Second, there is a strong element 11 of subjectivity to the growth rate, due to the uncertainty about future earnings and 35
Direct Testimony of Adam H. Gatewood Docket No. l 8-KCPE-480-RTS 1 dividends.
2 Q. How did you estimate the growth rate in the DCF model?
3 A. The appropriate growth estimate is that which is expected by the market and factored into 4 investors' analyses to estimate stock prices. That is, it is the growth estimate investors 5 used to determine the stock price. Earnings per share growth forecasts are commonly 6 incorporated into the DCF model. Investment firms that publish growth forecasts typically .
7 publish three to five-year annual growth estimates for earnings. Value-Line Investment 8 Survey also provides dividend growth rate forecasts; it is the only firm that I am aware of 9 that does so. Three to five years is as far into the future as analysts forecast for a specific
. 10 company.
11 Q. How do investors estimate the dividend growth rate beyond the three to five-year 12 h.orizon of the short-term growth forecasts?
13 A. For a long-terin perspective of potential growth, investors rely on forecasts of the broad 14 economy as measured by annual changes forecasted for the nation's gross domestic product 15 (GDP). There are sources for long-term growth estimates of this country's GDP that extend 16 out more than 20 years. Academic texts and investment professionals use these forecasts 17 in DCF models as a forecast of potential long-term growth of corporate dividend payments.
18 GDP refers to the market value of all final goods and services produced within a country 19 in a given period. Nominal GDP (nGDP) is that measure of goods and services which 20 includes effects of price changes - better known as inflation. Inflation must be included 21 for our forecast because the DCF analysis is interested in the nominal required return. That 36
Direct Testimony of Adam H. Gatewood Docket No. l 8-KCPE-480-RTS 1 is to say; investors' expectations of inflation are contained in their required return. Keep 2 in mind that the "headline" GDP reported in the media is real GDP, which is GDP less the
\
3 inflation experienced over the measurement period.
4 Q. Is it accepted practice in securities valuation to use nGDP growth estimates in the 5 DCF model?
6 A. Yes, in the federal regulatory arena, similar to the responsibilities of the KCC, the Federal 7 Energy Regulatory Commission (FERC) uses nGDP to estimate the cost of equity. FERC 8 has reviewed the issue of long-term growth estimates used in DCF models. It took 9 comments . from .stakeholders that includeq. state commissions, customers, investment 10 bankers, and interstate pipeline companies. 26 Testimony from these parties made it clear 11 that long-term estimates of nGDP are a common component of valuation analyses 12 conducted by investment professionals. From that proceeding, FERC concluded that long-13 term growth estimates of nGDP should be the estimate or'long-term growth in the DCF 14 models used to estimate required returns for interstate pipeline companies because that is 15 consistent with investor behavior. 27 In June of 2014, FERC concluded that the same 16 methodology should be used in, setting the required returns for electric transmission 17
- companies. 28 Although the Commission has never explicitly endorsed long-run GDP 18 growth as an input, it is clear that the growth estimate used by Staff in*the 15-116 Docket 19 were considered credible by the Commission. 29 In that analysis, I relied on the same
26 Transcript from Technical Conference held on January 23, 2008: FERC Docket PL07-2-000.
27 Policy Statement, FERC Docket PL07-2-000 (April 17, 2008); FERC Opinion No. 486, FERC Docket RP04-274 (Oct. 19, 2006) ..
28 Opinion No. 531; June 19, 2014; 147 FERC 61,234; para 36.
29 Order issued September 10, 2015; Docket 15-KCPE-116-RTS; para. 34; p. 15-16.
37
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 sources for long-term nGDP growth as I am using in this analysis.
2 Q. Is there academic support for this issue?
3 A. Yes, academic research has shown that nGDP growth forecasts are an important input to 4 valuation studies because the analyst has to consider whether a company's annual earnings 5 can grow as fast as, or even faster than, the broad economy. In two of his books devoted 6 to the subject of asset valuation, Dr. Aswath Damodaran discusses the nature of a stable 7- growth rate for DCF models. 30 He argues for viewing nominal economic growth as the 8 absolute maximum when using a stable-growth model, such as the DCF model we are 9 usmg.
10 "The stable growth rate cannot exceed the growth rate of the economy in 11 which a firm operates, but it can be lower. There is nothing that prevents 12 us from assuming that mature firms will become a smaller part of the 13 economy and it may, in fact, be the more reasonable assumption to make.
14 Note that the growth rate of an economy reflects the contributions of both 15 young, higher growth firms and mature, stable growth firms. lf the former 16 grow at a rate much higher than the growth rate of the economy, the latter 17 have to grow at a rate that is lower. " (Damodaran on Valuation: Security 18 Analysis for Investment and Corporate Finance, 2nd edition; Aswath 19 Damodaran; p. 148) 20 "The growth rate ofa company cannot be greater than that of the economy 21 but it can be less. Firms can become smaller over time relative to the 22 economy. Thus, even though the cap on the growth rate may be the nominal 23 growth rate ofthe economy, analysts may use growth rates much lower than 24 this value for individual companies. " (Damodaran on Valuation: Security 25 Analysis for Investment and Corporate Finance, 2nd edition; Aswath 26 Damodaran; p.159) 30 Investment Valuation: Tools and Techniques for Determining the Value of Any Asset, 2nd Edition and Damodaran on Valuation: Security Analysis for Investment and Corporate Finance, 2nd Edition.
38
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 It is worth noting that Professor Damodaran cites the nGDP growth projection as a ceiling 2 for long-term growth in most valuation studies. Certainly, there are industries that will 3 exceed the average for a period of time, but even for those industries, rapid growth cannot 4 continue forever.
5 Q. Does the view that nGDP growth is a ceiling. on long-term earnings growth exist 6 outside of academia?
7 A. Yes, valuation analysts carefully consider the long-run growth rates used to value assets 8 very carefully because using an incorrect growth estimate will lead to incorrectly valuing 9 an asset: The authors of the previous discussion, Peter L. Bernstein and Robert D. Arnott, 10 have both been published in peer-reviewed academic journals and books on investment 11 strategy, as well as building careers in the field of asset management and investment 12 strategy.
13 Furthermore, institutions directly involved ip. asset valuation and asset management that 14 apply valuation models to analyze potential acquisition and merger transactions recognize 15 that estimates of firm-specific growth are a driver to the value of an asset; overstating 16 growth would cause a model to overestimate the value of the asset which would result in 17 an economic loss to the investor. These experts also warn of a ceiling to earnings growth 18 rates as being no mon;: than that of broad economic growth.
19 "Growth rate: Few companies can be expected to grow faster than the 20 economy for long periods. The best estimate is probably the expected long-21 term rate of consumption growth for the industry's products, plus inflation. "
22 (Valuation: Measuring and Managing the Value of Companies; Tim Koller, 23 Mark Goedhart, and David Wessels; McKinsey & Co; 4th ed; p. 275.)
39
Direct Testimony of Adam H. Gatewood Docket No. l 8-KCPE-480-RTS 1 The following quote from J.P. Morgan Asset Management (JPMAM) addresses the macro 2 or economy-wide measures of profits, and it is consistent with the firm-specific view 3 expressed by asset valuation experts in that analysts must be aware of the forecasted growth 4 rates applied in valuation models and how those growth forecasts comport with broad 5 measures of forecasted economic growth.
6 "One common mistake is to assume that earnings and dividends received 7 by investors can grow in line with-or even in excess of-overall economic 8 growth (GDP) in perpetuity. Granted, it is almost a truism that aggregate 9 earnings must grow at the same pace as the overall economy in the very 10 long run; otherwise, profits would eventually outstrip the size of the entire 11 economy or dwindle to an insignificant share of it. But not all of this 12 earnings growth accrues to existing shareholders. On the contrary, a large 13 portion of economic growth comes from the birth ofnew enterprises. Some 14 commentators suggest (for example, Bernstein and Arnott, 2003; Cornell, 15 2010) that new enterprises account for more than half of GDP growth in 16 the US., while in some rapidly developing economies new enterprises may 17 account for the lion's share of overall economic growth. " 31 18 Goldman Sachs Asset Management explains to its clients, "Our analysis reveals that the 19 link between GDP growth and equity returns is, in fact, very strong." 32 The asset pricing 20 formula of a dividend discount model shows how GDP growth influences the return they 21 earn on equity assets: " ... the dividend growth rate will equate to the growth rate in 22 earnings. Assuming that earnings growth is equal to, or just associated with GDP growth, 23 a direct link with equity returns is established." 33 Goldman Sachs also states that research 24 has demonstrated that GDP growth is a proxy for earnings growth.
31 Long-term Capital Market Return Assumptions: 2015 Estimates and Thinking Behind the Numbers; J.P. Morgan Asset Management; p. 25; https://am.jpmorgan.com/us/institutional/ltcmra.
32 "Linking GDP Growth and Equity Returns"; Monthly Insights: From the Office of the Chairman; Goldman Sachs Asset Management; May 2011; p. 1.
33 "Linking GDP Growth and Equity Returns"; Monthly Insights: From the Office of the Chairman; Goldman Sachs Asset Management; May 2011; p. 2.
40
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS 1 Q. Do you believe this evidence justifies incorporating long-run nGDP growth forecasts 2 into cost of equity analyses of utility companies?
3 A. Yes, because we h~ve to ascertain the discount rate investors apply to the future cash flows 4 from an investment in these utilities. Therefore, the Commission should emulate investors' 5 analytical practices as closely as possible to determine investors' discount rate. As noted 6 above, investment professionals include a long-run growth forecast for the general 7 economy (in addition to company-specific short-run growth estimates) when applying the 8 DCF and capital asset pricing model, and that measure of macro-economic growth serves 9 as the upper bounds of a firm-specific analysis. Therefore, the Commission should 10 , consider the same information when estimating a utility's required return.
11 Q. How did you estimate long-run nominal GDP growth?
12 A. I averaged the long-run nGDP forecasts of the Energy Information Agency (EIA) and the 13 Social Security Administration (SSA). The average of these two forecasts composes the 14 long-run growth estimate in the DCF analysis. The nGDP growth forecasts published by
, 15 . EIA and SSA-OADSI are the same sources that I have relied on over the past decade.
\
41
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS Nominal GDP Estimates En~!~W:or!llllti_onAg~!1CYJ~~p0_15 - 2Q50_ 4.19%
_, Social Security Administration (SSA) _____ * -*
OADSI Trustees Rep}>rt 2017 - 2095 _ 4.41%
1 Average 4.30%:
- *--- -- - --- - Estimates Additional GDP ---------
Exxon-Mobile 201? Outlook for Enerw 2015 - 2040 2.2% Real GDP + 2.2 GDP Deflator from SSA 4.40%
Congresssional Budget Office Nominal GDP Forecast
.2019 - 2020 3.50%
2021 - 2027 3.90%
Federal Reserve Open Market Committee Long-run Forecast 2.2% Real GDP + 2.0 PCE Inflation 4.20%
1 2 Q. Are these two the only two sources for long-run GDP forecasts?
3 A. There are other source shown in the table and they are wholly consistent with the EIA and 4 SSA forecasts.
5 DCF Results 6 A. Please discuss the results of your DCF analysis.
7 Q. The results of my DCF analysis appear in the following table. The results seen in this DCF 8 analysis are very much the same as the DCF results in my 18-095 analysis. As I have set 9 out the foundations for the DCF analysis in the previous pages, in this section, I will discuss 10 the specific information that I relied on for the DCF model and interpret the results.
42
Direct Testimony of Adam H. Gatewood Docket No. I 8-KCPE-480-RTS Staff Proxy Group
______
- _____ Discounted Cash Flow (DCF) Analysis -----------* __
18-KCPE-480-RTS I 2 3 4 5 Dividend Yields Growth DCF Estimated Min Max Rate Required Return
'Allele Inc ALE 2.88% 3.51% 4.91% 7.79% 8.42%
Alliant Energy Corp LNT 3.12% 3.85% 5.18% 8.30% 9.04%
,Arreren Corp AEE 2.99% 3.74% 5.38% 8.37% 9.12%
,Arrerican Electric Power Co. AEP 3.37% 4.19% 4.80% 8.17% 8.99%
"- - - --------- ----~-
Consolidated Edison Inc ED 3.30% 4.16% 3.78% 7.08% 7.95%
Duke Energy Corp New DUK 4.14% 5.28% 4.45% 8.59% 9.74%
- Edison lntemati~nal EIX 3.08% 4.46% 4.62% 7.71% 9.08%
- El_ Pa~o J;:lectric Co EE 2.49% 3.16% 4.88% 7.36% 8.04%
,IDACORP Inc IDA 2.56% 3.22% 4.33% 6.89% 7.55%
NorthWestern Corp. NWE 3.57% 4.60% 3.92% 7.49% 8.52%
OGE Energy Corp _ _}2GE 4.13% 5.20% 4.95% 9.08% 10.15%
Pinnacle West Capital Corp PNW 3.27% 4.11% 4.50% 7.77% 8.62%
Portland General Electric Co. POR 2.99% 3.84% 4.11% 7.10% 7.95%
Xcel Energy Inc XEL 3.06% 3.85% 4.97% 8.03% 8.82%
Average of each colwnn 7.84% 8.71%
Average ofall observations 8.28%
Range ofall observations 6.89% 10.15%
I) 2018 annual dividend divided bymaximwn price obsern,d from July 2, 2017 through July 3, 2018
- 2) 2018 annual dividend divided by minimwn price obsern,d July 2, 2017 through July 3, 2018 ____ _
,3) Fore~?5ted EPs_ gromh
'4) Low-end estimate = col I + col 3
- 5) High-el!~ est"!13te =_co_! 2 + col 3 1
2 Pricing data was gathered from Y ahooFinance for each of the proxy companies from the 3 time period of July 2, 2017, through July 3, 2018, on a weekly basis. The low dividend 4 yield is computed using the projected 2019 dividend divided by the average of the weekly 5 high prices while the high dividend yield is computed using the average weekly low prices.
6 Q. How did you arrive at a growth rate for each proxy company?
7 A. The growth rate is the average of the short-term growth rates 34 and the long-run forecast 8 of nGDP of 4.30%. The following table summarizes all of the observed growth forecasts, 34 For each proxy company, I gathered three short-run, three to five-year growth forecasts for earnings and dividend from Value-Line Investment Survey, as well as analysts' earnings growth projections by Thomson Financial Network (I/B/E/S) reported by YahooFinance. 1/B/E/S aggregates analysts' earnings forecasts and reports the mean of those estimates. FactSet is a service similar to 1/B/E/S in that it aggregates analysts' forecasts and publishes the mean and median of estimates. FactSet data was obtained through S&P Global Market Intelligence.
43
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 both historical and forecasted.
2 Q. How is the long-run nGDP forecast applied in your DCF analysis?
3 A. The long-run nGDP growth forecast of 4.30% is averaged with the short-run growth 4 forecasts. In my DCF analysis, I give equal weight to short-run and long-run growth 5 forecasts. The weighting is certainly debatable because we cannot know precisely how 6 investors weight the two forecast horizons. At FERC, in both natural gas pipeline and 7 electric transmission rate cases, the short-run growth is afforded a two-thirds weighting 8 and the nGDP forecast a one-third weighting. Whatever the weighting an analyst applies 9 between the short-term and long-term growth forecasts, the analysis needs to be 10 constructed in a manner that distinguishes between the growth potential of each time 11 horizon.
44
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS I I I Staff Proxy Group Growth Rate Sunnnary lS-KCPE-480-RTS I I I I 2 3 4 5 6 7 8 9. 10 11 Value-Line Historic Data Forecasted Growth Rates 10 Year SYear Value Line Thomson FactSet , Short-ruu Long-tenn DCF EPS DPS EPS DPS EPS DPS EPS EPS Average nGDP Growth Rate Allete Inc. ALE 1.50%1 3.50%1 5.50%1 3.00% 5.00% 4.50% 6.00% 6.60% 5.53% 4.30% 4.91%
Alliant Energy Coro. LNT 5.00%1 7.50%1 6.50%1 6.50% 6.50% 6.00% 5.85% 5.91% 6.06% 4.30% 5.18%
Am:ren Coro. AEE -1.00%1 -4.00%1 0.50%1 2.00% 7.50% 5.50% 6.30% 6.57% 6.47% 4.30% 5.38%
Am:rican Electric Power Co. AEP 3.00% 4.00% 5.50% 4.50% 4.50% 5.00% 5.79% 5.92% 5.30% 4.30%
- 4.80%
- J Consolidated Edison Inc. ED 2.50% I.SO% 2.00% 2.00% 3.00% 3.50% 3.39% 3.18%1 3.27% 4.30% 3.78%
Duke Energy Corp. DUK 2.50% 10.00% 0.50% ' 2.50*% 5.50% 4.50% 4.22%
- 4.2io/~i 4.61% 4.30% 4.45%
Edison International EIX 2.50% 6.00% 2.50% 9.00% 4.50% 8.00% 3.19% 4.10%* 4.95% 4.30% 4.62%
1 El Paso Electric Co. EE _ 6.50% _ 0.00% -- 0.00% !8.00% 4.50% 7.00% 5.20% 5.10% 5.45% 4.30% 4.88%
IDACORP Inc. IDA 7 ..50,'!'o 5,_50~ * ' 4.5.QY., 10.50% 3.50% 6.50% 3.55% 3.91%: 4.37% 4.30% 4.33%
NorthWestern Corp. NWE *- 8.00% _ 5.50% 7.00% _ 7.00% 3.50% 4.50% 3.16% ___3.01%, __ 3.54% 4.30% 3.92%
OGE Energy Corp. 4.50% 4.30% .. 410%:
Pinnacle West Capital Corp. PNW OGE 4.00% 2.50%
-*--- 5.50% 1.00%-- 8.50%
5.00% 2.50%
6.00%
5.00%
8.00%
5.50%
3.78% 4'.54%1 5.60%
4.70%
4.30%
4.30%
4.95%
4.50%
Portland General Electric Co. POR 4.00% 9.00% 3.50% 3.50% 4.00% 6.00% 2.65% 3.02%1 3.92% 4.30% 4.11%
1 Xcel Energy Inc. XEL 5.50% 4.50% 5.00% 5.50% 5.50% 5.50% 5.86% 5.67% 5.63% 4.30% 4.97%
Min -1.00%1 -4.00%1 0.00%1 2.00% 3.00% 3.50% 2.65% 3.01% 3.27% 3.78%
Max 8.00%1 10.00%1 7.00%1 18.00% 7.50% 8.00% 6.30% 6.60% 6.47% 5.38%
Mean 4.00%1 4.36%1 3.50%1 6.07% 4.89% 5.71% 4.52% 4.70% 4.96% 4.63%
I) Historic 10-year earning per share annual growth rate reported by Value-Line
- 2) Historic IO-year divdend per share annual growth rate reported by Value-Line
- 3) Historic 5-vear earnings per share annual growth rate reoorted by Value-Line
- 4) Historic 5-year dividend per share annual growth rate reported by Value-Line
- 5) 3 to 5-year forecasted annual earnings per share growth rate by Value-Line
- 6) 3 to 5-year forecasted annual dividends oer share growth rate bv Value-Line
- 7) 5-year forecasted annual earnings per share growth rate. Consensus forecasts gatherd by Thomson-Reuters and reported at YahooFinance on July 17, 2018
- 8) Long-term forecasted annual earnings per share growth rate. Consensus forecasts gathered by FactSet and reported at S&P Global Marketlntelligence (fka: SNL Financial) on July 17, 2018
- 9) Average of3 to 5-year forecasted annual growth rates
- 10) Lone-term forecasted nominal GDP growth rate ... - - -- - -- - - -- -- ----
- 11) Average of short-term and lone-term growth rates 1 I I I 2 Q. What are your observations of the short-run growth forecasts?
3 A. The average of the short-run growth forecasts for the proxy group is 4.96% with a range of 4 3.27% to 6.47%.
5 Internal Rate of Return QRR) Analysis 6 Q. Please discuss the internal rate of return (IRR) analysis that you performed.
7 A. An IRR analysis of an investment is a form of a discounted cash flow analysis, only with 8 a more complex equation than the Gordon Growth Model that we applied in the previous 9 section. In the IRR analysis, we are able to apply the five-year growth forecasts to only 45
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS 1 the intended next five years of dividends, with the remaining years growing at the long-run 2 nGDP forecasted growth rate. In the age of spreadsheets, the IRR equation is not that much 3 harder to manage than the basic dividend yield plus growth DCF model (a.k.a. Gordon 4 Growth Model) and, as the IRR model allows us to apply the growth forecasts to their 5 respective forecast periods, the IRR model provides important information to policy 6 makers because it recognizes the respective time spans of both the short-run (three to five-7 year earnings growth) and long-run (nGDP growth rate) forecasts. The full output of the 8 IRR calculations appears in Schedule AHG-5; the following table summarizes the results.
9 In the IRR model, short-term growth forecasts are given much less weight than in the two-10 stage DCF analysis; five years of a several hundred year time horizon or five percent as 11 opposed to a weighting of 50 percent that I applied in the two-stage DCF model. As a 12 result of the greater weighting of the long-term growth estimate, the average for the proxy 13 group in the IRR analysis is 16 basis points lower than the two-stage DCF results.
46
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS Staff Proxy Groue__ __ _
-,----- -- Internal Rate of Retum(IRR) 18-KCPE-480-RTS
- - - -- ~ - - ------*
!Allete Inc. ___________ ------*- 7.82%1
- !,lli~t_ ~!}e_rgy Corp. 8.23%:
_\Ameren C~rp~---------------- 8.19%,
1American Electric Power Co. 8.51%:
,Consolidated Edison Inc. 8.12%
iDuke Energy Corp. -9~44o/~:
,Edison International 8.39%:
!EI Paso Electric Co. 7.42%,
- IDACORP Inc. 7.39%
1 NorthWestern Corp. 8.58%
,OGE Energy Corp. 9.47%
!Pinnacle West Capital Corp. 8.28%'
,Portland General Electric Co. 7.93%
!xcel Ene;gy I~~:
- 8.18%,
Mean 8.28%'
Min 7.39%
Max 9.47%
1 2 In this instance, as is usually the case with public utilities, there is not a wide difference 3 between the short-term growth rates and long-te~ nGDP growth, therefore, the difference 4 in weighting of the two growth rates between the DCF and IRR analyses do not cause a 5 large difference in results.
6 Capital Asset Pricing Model (CAPM) Analysis 7 Q. Please describe the capital asset pricing model (CAPM).
8 A. The CAPM offers an explanation of the positive relationship between risk and ROR 9 required by investors. 35 It is appealing to regulators because it meets the legal standards I 10 discussed above, as it can be structured to iQ.corporate current data from the financial 35 The theoretical support for the CAPM is the work done by Harry Markowitz ("Portfolio Selection," Journal 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 Portfolio Analysis," Management Science, January, 1963).
47
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 markets and the unique risks of the utility in question.
2 Ke = Rf+ Beta (Rm - Rf) or 3 Ke= Rf+ Beta (Rp) 4 Where:
5 Ke = required return on equity 6 Rf= return on a risk-free security 7 Rm = an expected return from the market as a whole 8 Rp = risk premium available to investors through purchasing common stocks 9 instead ofrisk-free securities often calculated as Rm - Rf 10 Beta= volatility of the security's or portfolio's return relative to the volatility of 11 the market's return with the market beta equal to 1.0 12 Rf 13 . The Rf estimate is the interest rate investors believe represents a riskless return. Although 14
- it is a simple concept, the answer is not universally agreed upon. It is widely accepted that 15 a debt instrument issued by the U.S. Government is a risk-free instrument. An investment 16 in U.S. Treasury Bonds *is a risk-free investment if the investor plans to hold it until 17 maturity. The risk-free instrument chosen will have an effect on the results of the CAPM 18 analysis. Whichever instrument is selected; it should be used consistently in the equation.
19 Beta 20 The beta coefficient measures the volatility of the return earned by the utility's stock 21 relative to the volatility of the returns earned by the broader equity market. The broad 22 equity market is frequently measured using the S&P 500 Index. This measure provides a 48
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 look at the risk and volatility of a stock relative to other investments. A stock with a beta 2 of 1 is equally as volatile as the market as a whole. A stock with a beta of 0.5 is half as 3 volatile as the market. Value-Line's last report on Great Plains Energy, prior to the merger 4 closing, reported a beta coefficient of 0. 70; ~imilar to the average for the proxy group of .
5 0.67.
6 Rm 7 Rm is the expected return on the stock market as measured by a broad market index such 8 as the S&P 500. This represents the total return consisting of the price change of the index 9 plus dividends earned for the year.
10 Rp 11 The risk premium is the difference between investors' expected return from the stock 12 market and their expected return from the risk-free investment over the same time period.
13 The risk premium is written as Rm-Rf. The market return and the *risk-free return should 14 be taken from the same time period so as to accurately measure the additional return 15 required by investors to take on the risk of common stocks over the risk-free investment.
16 Q. Please discuss your CAPM analysis.
17 A. I took two distinct approaches to the CAPM analysis. I performed one analysis using 18 purely historic measures of returns from the stock and bond markets and a second analysis
- 19. using forecasted returns. The results using historic returns are drastically higher, 9.38%,
20 when compared to results using forecasted returns of 6.93%.
49
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS 1 Both forms of my CAPM analysis incorporate the high and low beta coefficients observed 2 in the proxy group. This beta indicates that the volatility of the proxy group is about 65%
3 of that exhibited by the broad market and, accordingly, investors would expect a relatively 4 lower return from stocks of public utilities than the broad market. This is a clear indication 5 that public utility companies like KCP&L and the proxy group are less risky than the broad 6 stock market, and investors expect a return lower than that *expected of the market.
7 Reviewing the high and low beta coefficients observed in the proxy group provides a 8 picture of the range that the new company could exhibit in the future.
B~tl! Co~!~c~nt~,_s~l!rr~ P.!_OE G~~P Updated on July 24, 2018 18-KCPE-480-RTS Allete Inc ALE 0.75.
Allfl!~t E.~<::!gy CC!_rJJ LNT 0.70 Ameren Corp_ AEE 0.65 American Electric- Power
... . Co Inc AEP 0.65
- Consolidated Edison Inc ED 0.50
,Duke Energy Corp New _ -* __ . DUK 0.60 Edison International EIX 0.60 El Paso Electric Co EE 0.75
. IDACORP Inc IDA 0.70 NorthWestern Corp NWE 0.65 OGE Energy Corp OGE 0.95 Pinnacle West Capital Corp PNW 0.65 Portland
--- -Electric Co General POR 0.65 Xcel Energy Inc XEL 0.60 Min 0.50 Source: Value-Line Investment Survey Max ,0.95 Me.an 0.67 Median 0.65 9
10 Q. Please describe the forecasted CAPM analysis.
11 A. For the forecasted CAPM, I relied on the* expected returns published by JP MAM in its 12 annual publication, Long-Term Capital Market Assumptions for 2018, to establish the 13 expected return for the market. JPMAM publishes 10 to 15-year forecasts of expected 50
Direct Testimony of Adam H. Gatewood Docket No. l 8-KCPE-480-RTS 1 returns on dozens of investment asset classes in its annual publication, the Long Term 2 Capital Market Return Assumptions (LTCMRA). JPMAM forecasts an annual return on 3 common stocks of 6.93%. The JPMAM's forecasted returns on common stocks has 4 declined over the past two years; generally a product of the "increase in stock prices over 5 the past two years.
6 Following the calculations and inputs through the CAPM equation in line 2 of the following 7 table, the forecasted return on a risk-free investment, 10-Year U.S. Treasury Bonds, is 8 subtracted from the expected return on common stocks resulting in a risk premium of 9 3.86%. This risk premium is the additional return necessary to induce investors to take on 10 the added risk associated with common stocks over the risk-free investment. The beta 11 coefficient is applied to the risk premium to ascertain how much of a risk premium is 12 necessary for.investors to take on risks of investing in utility stocks as opposed to the risk-13 free U.S. Treasury Bond.
51
Direct Testimony of Adam H. Gatewood DocketNo. 18-KCPE-480-RTS Capital Asset Pricing Model -- Fore casted Risk Pre_minm Using Forecasted Market Returns~ i;:reasury Bond Yields 18-KCPE-480-RTS Low Beta High Beta Avg Beta I) Fore<:aste~ ~1:t_l!f~ ~n C::ol1!111_'?n. Stocks 6.93%, 6.93% 6.93%,
- 2) Forecasted To~l Return on IO-Year T-Bonds 3.07%' 3.07% 3.07%;
- 3) Resultini~skPr~~lllll 3.86%' 3.86% 3.86%
- 4) Beta_ <:oe_!fi_cie1_1t __ x, o.so I 0.95 0.67, 5)_ Risk Premilllll 1.93%: 3.67% 2.59%
- 6) Forecasted Yield on IO-Year T-Bonds + 3.50%, 3.50% 3.50%
- 7) For Cost ofEquity 5.43% 7.17% 6.09%'
6.30%
I) Fore_ca~ted 10 to _IS-year3nn_1!3I ~ri!}mletic return 011_!,tqcks _
for mid-sized ~ompaniesby J .P_. Morgan Asset Management, 2018 E~ition
- 2) Forec_asted 19 to 15-y~ar anrn,ial ~i~etic r~_turn on intermediate term _
U.S. Government bonds_ by J.P. ~Or!?f111 Asset Mana&ement, 2018 Edition
- 3) Resulting risk premi~ (1-2)
- 4) Beta cpeffi cie11t ~.<!ng~ qf pi:_o~ gi:2._up_ ~eport~_d by Val l!e-!,i11_e
_ ~) Ro\_:\' 3 ~ Rq..y ~ = ~.5~!_5P.e_ci_!}£ ~~sk JJ_re_mi~ _ __
_ 6) _Forecasted_xield 01119-Y_ear U~_-_ Trea_!>_llr)'. bonds fo_!e~ge~ ~y J.P. Morgan Asset Management, 2018 Edition (page 55)
- 7) Forecasted cost of equity capital row 5 + row 6 Sources:
_J.P. Morgan Asset M~lplg~~!]!,_ ~ng-te~ 9apital Market Return As_slllllptio1!5, 2018 Edition; J.P. Mo_rgan Asset ~nagem~nt (published October of29_17)
- www.jpmorganinstitutional.com/pages/jpmorgan/am/ia/research and publications/long-term capital market
- -- - --* - - -- -** ---------- ----------?- *r ---- - - - - : - - - - ---
1 2 The expected risk-free yield of 3.50% forecasted by JPMAM is added to the beta specific 3 risk premium to arrive at the cost of equity for the given beta coefficient of 0. 70 - about 60 4 basis points less than the returns JPMAM is forecasting for the broad stock market indexes.*
5 These results appear low by historic measures of the past 40 years. The results are in line 6 with the returns offered on other investments in the current capital markets. For instance, 7 investors in KCP&L's long-term bonds are purchasing bonds with the expectation for 8 returns of less than 4.00%.
9 Q. Please discuss the historical CAPM analysis.
10 A. I performed a CAPM analysis incorporating historic data of returns earned from 1926 11 through 2014. The process is the same as that applied in the Forecasted CAPM.
52
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS
---~--C_apital Asset Pricing Model -- Historic Risk Premium Based on Historic ----- Risk Premiums from 1926 to 2015
--- ---------~---------
18-KCPE-480-RTS Low Beta High Beta Avg Beta lfl'otal Renn-~ ~nC~mmonStoc_!<s --*** ------ - 12.10% 12.10% 12.10%
- 2) j Total Return on Government Bonds ________ _ 5.20% 5.20% 5.20%
3), Resulti.ng Risk Premiwn 6.90% 6.90% 6.90%
- 4) ,Beta Coefficient 0.50 0.95 0.67 5)jRi;;-kPremiwn xi 3.45%1 6.56%1 4.62%1
- 6) J~-~t~ri_~Y~ld _CJ!} Q_CJve~nt Bqni:_ . + 4.38% 4.38% 4.38%
- 7) iForecasted Cost of Equity Based on Historic Returns 7.83% 10.93% 9.00%
l -- -- ' -- - - --
9.38%
I
- 1) 1Historic returns on common stocks 1926-2017 (SBBI; Exhibit 2-3)
- 2) ;Historic returns on intermediate-term government bonds 1926-2017
- 3) \~eslllrjng_risk IJr_el!lil_ll!lJl-2) _
4):Beta coefficient ofthe proxy grm.l}l (Reported by Value-Line) 5)IRow I *-*
3 xRow 4 = As~et S}lecific Risk:P;e~~
- . - -*-*-*. --*-*-* ~--- -
- 6) 1Historic year-end yield on intermediate-term government bonds 1926-2017 7);F~rei:~t~d~o~t~f~q~ty-capi~!;_r_~~5+-~~~6 * * -- * -
Sources:---- ---- ---- ----
Ibbotson SBBI: 2018 Classic Yearbook (Duff & Phelps) & Value-Line Investment Survey 1
2 In relying on purely historic data, we are assuming that certain trends observed in the past 3 80 years will continue in the future. Most notably, we would be assuming that the returns 4 observed on common stocks from decades past will continue in the future, which of course 5 assumes this historical data accurately measures the past returns. There is strong evidence I
6 that these :frequently-quoted returns do not present a complete picture of historic retums. 36 7 The simple step of beginning measurement period in 1926 brings questions as to whether 8 the time period represents all of the modem-era securities trading. The historic returns are 9 reported and might influence expectations despite warnings that surround historic 10 economic growth rates. There are well regarded financial publications that focus solely on 11 this type of historic data and how to apply it in cost of capital studies. Thus, I have to argue 36 McQuarrie, Edward F; "The Myth of 1926: How Much Do We Know Long-Term Returns on U.S. Stocks?"; The Journal oflnvesting; Winter 2009; p. 96.
53
Direct Testimony of Adam H. Gatewood Docket No. 18-KCPE-480-RTS 1 that the historic data is part of the cost of capital universe, although given only light 2 consideration in the final decision.
3 Q. Does that conclude your testimony?
4 A. Yes, thank you.
54
Schedule AHG - 1 18-KCPE-480-RTS Weighted
- Escalation Rate*** Composite 2.80% 1.80% 2.60% 5.70% 2.30% 2.91%
Escalate~ Costs From
- Table 3.2 SAFESTOR Alternative (thousands, 2017 $'s) Cost Categories*** Time 2017 Dollars Equip& from Total KCP&L Year Labor Materials Energy Burial Other Total 2017 Inflatc:;d Costs KS Allocated 2045 $ 50,301 $ 1,936 $ 1,969 $ 33 $ 9,446 $ 63,685 28 $ 134,230,644 $ 27,638,208 2046 $ 52,967 $ 10,775 $ 1,832 $ 1,389 $ 23,599 $ 90,562 29 $ 192,477,968 $ 39,631,383 2047 $ 28,085 $ 6,228 $ 486 $ 15 $ 6,065 $ 40,879 30 $ 88,071,073 $ 18,133,912 2048 $ 28,162 $ 6,245 $ 487 $ 16 $ 6,082 $ 40,992 31 $ 90,623,909 $ 18,659,543 2049 $ 28,085 $ 6,228 $ 486 $ 15 $ 6,065 $ 40,879 32 $ 92,731,922 $ 19,093,585 2050 $ 20,521 $ 4,415 $ 411 $ 13 $ 4,624 $ 29,984 33 $ 69,834,217 $ 14,378,927 2051 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 34 $ 12,975,580 $ 2,671,683 2052 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 35 $ 13,352,715 $ 2,749,336 2053 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 36 $ 13,670,261 $ 2,814,719 2054 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 37 $ 14,031,645 $ 2,889,128 2055 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 38 $ 14,402,734 $ 2,965,536 2056 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 39 $ 14,821,931 $ 3,051,849 2057 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 40 $ 15,175,096 $ 3,124,566 2058 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 41 $ 15,576,923 $ 3,207,302 2059 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 42 $ 15,989,562 $ 3,292,265 2060 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 43 $ 16,455,607 $ 3,388,224 2061 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 44 $ 16,848,473 $ 3,469,116 2062 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 45 $ 17,295,365 $ 3,561,131 2063 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 46 $ 17,754,307 $ 3,655,627 2064 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 47 $ 18,272,546 $ 3,762,333 2065 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 48 $ 18,709,681 $ 3,852,340 2066 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 49 $ 19,206,804 $ 3,954,698 2067 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 50 $ 19,717,364 $ 4,059,823 2068 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 51 .$ 20,293,775 $ 4,178,506 2069 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 52 $ 20,780,288 $ 4,278,680 2070 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 53 $ 21,333,426 $ 4,392,571 2071 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 54 $ 21,901,550 $ 4,509,548 2072 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 55 $ 22,542,816 $ 4,641,586 2073 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 56 $ 23,084,431 $ 4,753,105 2074 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 57 $ 23,700,055 $ 4,879,862 2075 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 58 $ 24,332,401 $ 5,010,063 2076 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 59 $ 25,046,004 $ 5,156,994 I 2077 $ 3,437 $ 322 $. 243 $ 7 $ 1,370 $ 5,379 60 $ 25,649,136 $ 5,281,180 2078 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 61 $ 26,334,497 $ 5,422,296 2079 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 62 $ 27,038,525 $ 5,567,256 2080 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 63 $ 27,832,842 $ 5,730,807 2081 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 64 $ 28,504,690 $ 5,869,141 2082 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 65 $ 29,267,916 $ 6,026,290 2083 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 66 $ 30,051,993 $ 6,187,732 2084 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 67 $ 30,936,415 $ 6,369,835 2085 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 68 $ 31,685,059 $ 6,523,982 2086 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 69 $ 32,535,274 $ 6,699,041
Schedule AHG - 1 18-KCPE-480-RTS Weighted
(
- Escalation Rate*** Composite 2.80% 1.80% 2.60% 5.70% 2.30% 2.91%
Escalated Costs From
- Table 3.2 SAFESTOR Alternative (thousands, 2017 $'s) Cost Categories *** Time 2017 Dollars Equip & from Total KCP&L Year Labor Materials Energy Burial Other Total 2017 Inflated Costs KS Allocated 2087 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 70 $ 33,408,789 $ 6,878,899 2088 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 71 $ 34,393,851 * $ 7,081,724 2089 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 72 $ 35,228,375 $ 7,253,554 2090 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 73 $ 36,175,823 $ 7,448,634 2091 $ 3,437 $ 322 $ 243 $ 7 $ -1,370 $ 5,379 74 $ 37,149,327 $ 7,649,079 2092 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 75 $ 38,246,858 $ 7,875,062 2093 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 76 $ 39,177,485 $ 8,066,679 2094 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 77 $ 40,233,688 $ 8,284,152 2095 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 78 $ 41,319,046 $ 8,507,628 2096 $ 3,446 $ 323 $ 243 $ 7 $ 1,374 $ 5,393 79 $ 42,542,342 $ 8,759,506 2097 $ 3,437 $ 322 $ 243 $ 7 $ 1,370 $ 5,379 80 $ 43,580,588 $ 8,973,281 2098 $* 8,030 $ 526 $ 530 $ IO $ 1,416 $ 10,512 81 $ 91,483,641 $ 18,836,562 2099 $ 39,843 $ 3,003 $ 2,428 $" 35 $ 1,725 $ 47,034 82 $ 430,839,660 $ 88,710,266 2100 $ 51,668 $ 21,348 $ 2,352 $ 19,715 $ 11,194 $ 106,277 83 $ 2,662,274,613 $ 548,164,690 2101 $ 52,224 $ 26,356 $ 2,272 $ 29,879 $ 16,007 $ 126,738 84 $ 3,922,244,251 $ 807,593,549 2102 $ 43,514 $ 7,481 $ 1,821 $ 10,054 $ 5,614 $ 68,484 85 $ 1,662,739,234 $ 342,359,474 2103 $ 43,514 $ 7,481 $ 1,821 $ 1)0,054 $ 5,614 $ 68,484 86 $ 1,741,171,137 $ 358,508,672 2104 $ 36,028- $ 4,171 $ 1,047 $ 4,233 $ 3,422 $ 48,901 87 $ 978,573,603 $ 201,489,168 2105 $ 19,989 $ 11,805 $ 289 $ 6. $ 1,828 $ 33,917 88 $ 300,897,026 $ 61,954,963 2106 $ 11,872 $ 9,571 $ 164 $ $ 1,237 $ 22,844 89 $ 196,446,660 $ 40,448,540 Total $ 676,450 $ 142,715 $ 29,816 $ 75,796 $ 168,376 $ 1,093,153 Source: Decommissioning Cost Analysis for the Wolf Creek Generating Station; prepared by TLG Services; August 2017; Table 3.2; p68 of 139 Kansas allocator for Wolf Creek; KCC DR #164 43.8%
KCP&L Ownership 47.0%
Schedule AHG-1 18-KCPE-480-RTS Kansas City Power & Light-Ks SAFESTOR Decommissioning
$ 2,036,766 Annual Payment Annual Annual Annual Annual Time Year Inflow Outflow Earnings Balance Return 2018 $ 2,036,766 $ $ 96,010,166 4.62%
, 2 2019 $ 2,036,766 $ $ 4,483,728 $ 102,530,660 4.62%
3 2020 $ 2,036,766 $ $ 4,785,043 $ 109,352,468 4.62%
4 2021 $ 2,036,766 $ $ 5,100,281 $ 116,489,515 4.62%
5 2022 $ 2,036,766 $ $ 5,430,087 $ 123,956,368 4.62%
6 2023 $ 2,036,766 $ $ 5,775,133 $ 131,768,268 4.62%
7 2024 $ 2,036,766 $ $ 6,136,124 $ 139,941,158 4.62%
8 2025 $ 2,036,766 $ $ 6,513,797 $ 148,491,721 4.62%
9 2026 $ 2,036,766 $ $ 6,908,922 $ 157,437,408 4.62%
10 2027 $ 2,036,7~6 $ $ 7,322,305 $ 166,796,480 4.62%
11 2028 $ 2,036,766 $ $ 7,754,792 $ 176,588,038 4.62%
12 2029 $ 2,036,766 $ $ 8,207,264 $ 186,832,067 4.62%
13 2030 $ 2,036,766 $ $ 8,680,644 $ 197,549,478 4.62%
14 2031 $ 2,036,766 $ $ 9,175,900 $ 208,762,144 4.62%
15 2032 $ 2,036,766 $ $ 9,694,042 $ 220,492,952 4.62%
16 2033 $ 2,036,766 $ $ 10,236,127 $ 232,765,845 4.62%
17 2034 $ 2,036,766 $ $ 10,803,263 $ 245,605,874 4.62%
18 2035 $ 2,036,766 $ $ 11,396,606 $ 259,039,246 4.62%
19 2036 $ 2,036,766 $ $ 12,017,367 $ 273,093,379 4.62%
20 2037 $ 2,036,766 $ $ 12,666,814 $ 287,796,959 4.62%
21 2038 $ 2,036,766 $ $ 13,346,272 $ 303,179,997 4.62%
22 2039 $ 2,036,766 $ $ 14,057,129 $ 319,273,892 4.62%
23 2040 $ 2,036,766 $ $ 14,800,834 $ 336,111,492 4;62%
24 2041 $ 2,036,766 $ $ 15,578,906 $ 353,727,165 4.62%
25 2042 $ 2,036,766 $ $ 16,392,934 $ 372,156,864 4.62%
26 2043 $ 2,036,766 $ $ 17,244,577 $ 391,438,208 4.62%
27 28 29 2044 $
2045 $.
2046 $
2,036,766 $
(27,638,208)
(39,631,383) 18,135,576 $
19,020,688 $
18,622,469 $
411,610,550 402,993,030 381,984,115 4.62%
4.62%
4.62%
30 2047 $ $ (18,133,912) $ 17,651,639 $ 381,501,843 4.62%
31 2048 $ $ (18,659,543) $ 17,629,353 $ 380,471,653 4.62%
32 2049 $ $ (19,093,585) $ 17,581,747 $ 378,959,815 4.62%
33 2050 $ $ (14,378,927) $ 17,511,885 $ 382,092,773 4.62%
34 2051 $ $ (2,671,683) $ 17,656,660 $ 397,077,750 4.62%
35 2052 $ $ (2,749,336) $ 18,349,122 $ 412,677,536 4.62%
36 2053 $ $ (2,814,719) $ 19,069,994 $ 428,932,811 4.62%
37 2054 $ $ (2,889,128) $ 19,821,157 $ 445,864,840 4.62%
38 2055 $ $ (2,965,536) $ 20,603,593 $ 463,502,897 4.62%
39 2056 $ $ (3,051,849) $ 21,418,654 $ 481,869,702 4.62%
40 2057 $ $ (3,124,566) $ 22,267,392 $ 501,012,528 4.62%
41 2058 $ $ (3,207,302) $ 23,151,989 $ 520,957,215 4.62%
42 2059 $ $ (3,292,265) $ 24,073,641 $ 541,738,592 4.62%
43 2060 $ $ (3,388,224) $ 25,033,957 $ 563,384,325 4.62%
44 2061 $ $ (3,469,116) $ 26,034,215 $ 585,949,424 4.62%*
45 2062 $ $ (3,561,131) $ 27,076,957 $ 609,465,251 4.62%
46 2063 $ $ (3,655,627) $ 28,163,633 $ 633,973,256 4.62%
47 2064 $ $ (3,762,333) $ 29,296,158 $ 659,507,081 4.62%
Schedule AHG- 1 18-KCPE-480-RTS Kansas City Power & Light-Ks SAFESTOR Decommissioning
$* 2,036,766 Annual Payment Annual Annual Annual Annual Time Year Inflow Outflow Earnings Balance Return 48 2065 $ $ (3,852,340) $ 30,476,086 $ 686,130,827 4.62%
49 2066 $ $ (3,954,698) $ 31,706,380 $ 713,882,509 4.62%
50 2067 $ $ "(4,059,823) $ 32,988,796 $ 742,811,483 4.62%
51 2068 $ $ (4,178,506) $ 34,325,616 $ 772,958,592 4.62%
52 2069 $ $ (4,278,680) $ 35,718,726 $ 804,398,639 4.62%
53 2070 $ $ (4,392,571) $ 37,171,583 $ 837,177,650 4.62%
54 2071 $ $ (4,509,548) $ 38,686,314 $ 871,354,416 4.62%
55 2072 $ $ (4,_~41,586) $ 40,265,636 $ 906,978,466 4.62%
56 2073 $ $' (4,753,105) $ 41,911,838 $ 944,137,199 4.62%
57 2074 $ $ (4,879,862) $ 43,628,958 $ 982,886,295 4.62%
58 2075 $ $ (5,010,063) $ 45,419,569 $ 1,023,295,801 4.62%
59 2076 $ $ (5,156,994) $ 47,286,908 $ 1,065,425,715 4.62%
60 2077 $ $ (5,281,180) $ 49,233,748 $ 1,109,378,284 4.62%
61 2078 $ $ (5,422,296) $ 51,264,814 $ 1,155,220,802 4.62%
62 2079 $ $ (5,567,256) $ 53,383,215 $ 1,203,036,761 4.62%
63 2080 $ $ (5,730,807) $ 55,592,810 $ 1,252,898,764 4.62%
64 2081 $ $ (5,869,141) $ 57,896,953 $ 1,304,926,576 4.62%
65 2082 $ $ (6,026,290) $ 60,301,179 $ 1,359,201,466 4.62%
66 2083 $ $ (6,187,732) $ 62,809,243 $ 1,415,822,977 4.62%
67 2084 $ $ (6,369,835) $ 65,425,746 $ 1,474,878,888 4.62%
68 2085 $ $ (6,523,982) $ 58,309,632 "$ 1,526,664,538 3.95%,
69 2086 $ $ (6,699,041) $ 60,356,988 $ 1,580,322,485 3.95%
70 2087 $ $ (6,878,899) $ 62,478,365 $ 1,635,921,951 3.95%
71 2088 $ $ (7,081,724) $ 64,676,502 $ 1,693,516,728 3.95%
72 2089 $ $ (7,253,554) $ 66,953,523 $ 1,753,216,698 3.95%
73 2090 $ $ (7,448,634) $ 69,313,773 $ 1,815,081,836 3.95%
74 2091 $ $ (7,649,079) $ 71,759,623 $ 1,879,192,381 3.95%
75 2092 $ $ * (7,875,062) $ 64,743,439 $ 1,936,060,758 3.45%
76 2093 $ $ (8,066,679) $ 66,702,714 $ 1,994,696,794 3.45%
- 77. 2094 $ $ (8,284,152) $ 68,722,890 $ 2,055,135,531 3.45%
78 2095 $ $ (8,507,628) $ 70,805,173 $ 2,117,433,077 3.45%
79 2096 $ $ (8,759,506) $ 72,951,498 $ 2,181,625,069 3.45%
80 2097 $ $ (8,973,281) .$ 75,163,092 $ 2,241;814,880 3.45%
81 2098 $ $ (18,836,562) $ 47,024,287 $ 2,276,002,605 2.09%
82 2099 $ $ (88,710,266) $ 47,613,974 $ 2,234,906,314 2.09%
83 2100 $ $ (548,164,690) $ 46,754,240 $ 1,733,495,864 2.09%
84 2101 $ $ (807,593,549) $ 36,264,733 $ 962,167,048 2.09%
85 2102 $ $ (342,359,474) $ 20,128,535 $ 639,936,J 09 2.09%
86 2103 $ $ (358,508,672) $ 13,387,463 $ 294,814,900 2.09%
87 2104 $ $ (201,489,168) $ 6,167,528 $ 99,493,260 2.09%
88 2105 $ $ (61,954,963) $ 2,081,399 $ 39,619,696 2.09%
89 2106 $ $ (40,448,540) $ 828,844 $ (0) 2.09%
Schedule AHG - 2 18-KCPE-480-RTS Estimates of Returns on Nuclear Decommissioning Trusts Across Investment Periods JPMAM Long-Term Capital Market Assumptions w/Fees Pre-Tax 2017 MW! Asset Proj. Weighted After Arithmatic Arithmatic . Time Period 1 Weight Return Return Tax Equities-Large Cap 7.63% 6.41% Equities-Large Cap 27.00% 6.30% 1.70% 1.36%
Equities-Small Cap 8.67% 7.35% Equities-Small Cap 6.00% 7.24% 0.43%. 0.35%
Equities-International (EAFE) 7.95% 7.61% Equities-International (EAFE) 20.00% 7.50%
- 1.50% 1.20%
Core Bonds 3.44% 3.67% Core Bonds 25.00% 3.45% 0.86% 0.69%
High Yield Bonds 6.13% 5.59% High Yield Bonds '17.00% 5.37% 0.91% 0.73%
Real Estate 7.32% 7.42% Real Estate 5.00% 7.31% 0.37% 0.29%
Cash & Equivalents 2.00% 2.00% Cash & Equivalents 0.00% 1.78% 0.00% 0.00%
Equity Management Fees O. l l % see DR KCC-258 Fixed Income Management Fees 0.22% Time Period 2 Tax Rate 20.00% Equities-Large Cap 20.00% 6.30% 1.26% 1.01%
Equities-Small Cap 5.00% 7.24% 0.36% 0.29%
Equities-International (EAFE) 12.00% 7.50% 0.90% 0.72%
Core Bonds 44.00% 3.45% 1.52% 1.21%
SAFESTOR Methodology 2018-2106 High Yield Bonds 8.00% 5.37% 0.43% 0.34%
Pre-Tax Post-Tax Real Estate 5.00% 7.31% 0.37% -o.29%
Time Period 1 2017-2084 5.78% 4.62% Cash & Equivalents 6.00% 1.78% 0.11% 0.09%
Time Period 2 2085-2091 4.94% 3.95%
Time Period 3 2092-2097 4.31% 3.45% Time Period 3 Time Period 4 2098-2106 2.62% 2.09% Equities-Large Cap 10.00% 6.30% 0.63% 0.50%
Equities-Small Cap 5.00% 7.24% 0.36% 0.29%
Sources: J.P.Morgan Asset Management Equities-International (EAFE) 5.00% 7.50% 0.38% 0.30%
2018 & 2017 Long-term Asset Returns Core Bonds 57.00% 3.45% 1.97% 1.57%
High Yield Bonds 8.00% 5.37% 0.43% 0.34%
Real Estate 5.00% 7.31% 0.37% 0.29%
Cash & Equivalents 10.00% 1.78% 0.18% 0.14%
Time Period 4 Equities-Large Cap 0.00% 6.30% 0.00% 0.00%
Equities-Small Cap 0.00% 7.24% 0.00% 0.00%
Equities-International (EAFE) 0.00% 7.50% 0.00% 0.00%
Core Bonds 50.00% 3.45% 1.73% 1.38%
High Yield Bonds 0.00% 5.37% 0.00% 0.00%
Real Estate 0.00% 7.31% 0.00% 0.00%
Cash & Equivalents 50.00% 1.78% 0.89% 0.71%
..J\.,H\.,UUU., I'.HJ.'U - J 18-KCPE-480-RTS 0
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5yr. 94.3 67.5
.. .. 25.30 24.50 25.23 27.33 24.57 21.57 25.34 24.75 24.40 24.60 24.n 30.27 27.01 27.78 27.95 28.65 Revenues per sh 31.25
.. .. 2.97 3.85 4.14 4.42 4.23 3.57 4.35 4.91 5.01 5.35 5.68 6.79 7.08 6.59 6.85 7.20 "Cash Flow" per sh 8.50
.. .. 1.35 2.48 2.77 3.08 2.82 1.89 2.19 2.65 2.58 2.63 2.90 3.38 3.14 3.13 3.40 3. 60 Earnings per sh A 4.25
.. .. .30 1.25 1.45 1.64 1.72 1.76 1.76 1.78 1.84 1.90 1.96 2.02 2.08 2.14 2.24 2.34 Div'd Decl'd per sh a* t 2.70
.. .. 2.12 1.95 3.37 6.82 9.24 9.05 6.95 6.38 10.30 7.93 12.48 5.84 5.35 4.08 6.30 6.90 Cap'I Spending per sh . 6.75
.. .. 21.23 20.03 21.90 24.11 25.37 26.41 27.26 28.78 30.48 32.44 35.06 37.07 38.17 40.47 41.75 43.00 Book Value per sh c 47.25
.. .. 29.70 30.10 30.40 30.80 32.60 35.20 35.80 37.50 39.40 41.40 45.90 49.10 49.60 51.10 51.50 52.00 Common Shs Outst'g O 53.50
.. .. 25.2 17.9 16.5 14.8 13.9 16.1 16.0 14.7 15.9 18.6 17.2 15.1 18.6 23.0 Bold fig res are Avg Ann'I PIE Ratio 15.0
.. .. 1.33 .95 .89 .79 .84 1.07 1.02 .92 1.01 1.05 .91 .76 .98 1.14 Value Line Relative P/E Ratio .85
- ** .9% 2.8% 3.2% 3.6% 4.4% 5.8% 5.0% 4.6% 4.5% 3.9% 3.9% 4.0% 3.6% 3.0% estln ates Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUCTURE as of 3/31/18 801.0 759.1 907.0 928.2 961.2 1018.4 1136.8 1486.4 1339.7 1419.3 1440 1490 Revenues ($mill) 1670 Total Debt $1502.7 mill. Due in 5 Yrs $450.5 mill. 82.5 61.0 75.3 93.8 97.1 104.7 124.8 163.4 155.3 159.2 175 185 Net Profit ($mill) 225 LT Debt $1396.5 mill. LT Interest $58.5 mill. 34.3% 33.7% 37.2% 27.6% 28.1% 21.5% 22.6% 19.4% 11.3% 14.8% NMF NMF Income Tax Rate NMF (LT interest earned: 3.8x) 5.8% 12.8% 8.9% 2.7% 5.3% 4.4% 6.3% 2.0% 1.4% .8% 2.0% 2.0% AFUDC %to Net Profit 1.0%
Leases, Uncapitalized Annual rentals $14.2 mill. 41.6% 42.8% 44.2% 44.3% 43.7% 44.6% 44.2% 46.3% 42.0% 41.0% 41.0% 39.5% Long-Tenn Debt Ratio 40.0%
58.4% 57.2% 55.8% 55.7% 56.3% 55.4% 55.8% 53.7% 58.0% . 59.0% 59.0% 60.5% Common Equity Ratio 60.0%
Pension Assets-12/17 $628.2 mill. 1415.4 1625.3 1747.6 1937.2 2134.6 2425.9 2882.2 3388.9 3263.4 3507.4 3645 3700 Total Capital ($mill) 4225 Oblig $793.2 mill. 1387.3 1622.7 1805.6 1982.7 2347.6 2576.5 3286.4 3669.1 3741.2 3822.4 3970 4140 Net Plant ($mill) 4350 Pfd Stock None 6.7% 4.8% 5.4% 6.0% 5.6% 5.3% 5.2% 5.8% 5.8% 5.5% 5.5% 6.0% Return on Total Cap'I 6.0%
Common Stock 51,271,007 shs. 10.0% 6.6% 7.7% 8.7% 8.1% 7.8% 7.8% 9.0% 8.2% 7.7% 8.0% 8.5% Return on Shr. Equity 9.0%
10.0% 6.6% 7.7% 8.7% 8.1% 7.8% 7.8% 9.0% 8.2% 7.7% 8.0% 8.5% Return on Com Equity E 9.0%
MARKET CAP: $3.8 billion (Mid Cap) 3.9% .5% 1.5% 2.9% 2.3% 2.2% 2.5% 3.6% 2.8% 2.4% 3.0% 3.0% Retained to Com Eq 3.0%
ELECTRIC OPERATING STATISTICS 61% 93% 81% 66% 71% 72% 67% 60% 66% 68% 65% 65% All Div'ds to Net Prof 64%
2015 2016 ~J~f-,-B~U~Sl~N~E~SS~:~A~L~LE~T~E-,l-nc~.-is-t-he-'-pa-re-n-to-f~M-in-n-es-o~ta_P_o_w-erL,w-h-ic_h_._p_ro-je_c_tsL.A-c_q_'d_UL.S-.-W-a-teLr-S-eN-i-ceLs-2-,1-5.-H-a_s_re_a_le_s_ta-te-o~p-er-at-io-n~
%Change Retail Sales (KWH) -8.9 -2.3 Avg. lndust. Use (MWH) NA NA NA supplies electricity to 146,000 customers in northeastern MN, & Su- in FL Generating sources: coal & lignite, 41%; wind, 12%; other, Avg. Indus!. Revs.JI.er KWH (¢) 6.40 NA NA perior Water, Light & Power in northwestern WI. Electric rev. break- 6%; purchased, 41%. Fuel costs: 28% of revs. '17 deprec. rate:
Capaci~ al Peak (Mw)
- 1942 NA NA down: !aconite mining/processing, 26%; paper/wood products, 9%; 3.2%. Has 2,000 employees. Chairman, President & CEO: Alan R.
Peak Load, Wnter (Mw)
Annual load Factor(%)
1631 1520 15 NA NA JR other industrial, 8%; residential, 12%; commercial, 13%; wholesale, Hodnik. Inc.: MN. Address: .30 West Superior St., Duluth, MN
%ChangeCustomers(avg.) NA NA NA f--1-6%_,_o_th_er_,_16_%_,._A_L_LE_T_E_c_1_ea_n_E_n_er..:.g~y-ow_n_s_r_en_e_w_ab_le_en_e~rg:.:.y_5_5_80_2_-2_0_93_._Te_1._:_21_0_~_79_*_50_0_0._1_nt_er_ne_t:_www __.a_ll_et_e._co_m_._ _-1 f~edChargeCov.(%) 381 318 339 ALLETE's primary utility subsidiary to acquisitions), and should benefit (by
'"A_N_N_u""'A~L-M""'T~E-S_P_a-st~-P-a-st-E-st-,d-,- 15-.,- 17-1 has appealed its rate order. In the first $0.10 a share) from the lower federal tax ofchange(persh) 10Yrs. svrs. to'21-'23 quarter of 2018, Minnesota Power was rate. (ALLETE will probably have a nega-Revenues 1.0% 2.5% 1.5% granted a rate increase of $13 million tive tax rate due to the effects of tax cred-
"Cash Flow" 5.0% 7.5% 3.5% (retroactive to the start of 2017), bas~d on its for renewable energy.) Our 2018 es-
~tTci~RJs Book Value t~~
6.0%
t5~
6.0%
~:~~
3.5%
a return of 9.25% on a common-equity ra- timate of $3.40 a share is within the com-tio of 53.81 %. The utility was disappointed pany's targeted range of $3.20-$3.50. We Cal- QUARTERLY REVENUES($ mill.) Full with some aspects of the decision (includ- look for profit growth in 2019 in line with endar Mar.31 Jun. 30 Sep. 30 Dec. 31 Year ing the allowed ROE), and asked the Min- management's goal of 5%-7% annually.
_ . _ _ .4 nesota Public Utilities Commission The company's utility in Wisconsin 2015 320 0 323 3 462 5 380 6 1486 2016 333.8 314.8 349_6 341. 5 1339.7 (MPUC) for reconsideration. It is seeking plans to file a rate case later this year.
2017 365.6 353.3 362.5 337.9 1419.3 changes that, if granted, would provide an Superior Water, Light & Power got a more 2018 358.2 351.8 380
- 350 1440 additional $20 million-$25 million in an- fruitful result in its last application, when 2019 365 360 400 365 1490 nual revenues. The MPUC's ruling is ex- it was granted an allowed ROE of 10.5%.
Cal- EARNINGS PER SHARE A Full pected in mid-2018. Whatever happens, However, this utility is much smaller than endar Mar.31 Jun. 30 Sep. 30 Dec. 31 Year the utility is unlikely to earn its allowed Minnesota Power.
2015 _85 .45 1.23 .83 3.38 ROE this year, despite cost-reduction ALLETE is proposing to build a gas-2016 .93 .50 .81 .89 3.14 measures it is taking. Even so . . . fired plant. The company's 50% stake in 2017 .97 .72 .88 .56 3.13 Earnings are likely to advance solidly the project would cost an estimated $350 2018 .99 .61 .95 .85 3.40 this year and next. Minnesota Power is million. Minnesota Power would purchase 2019 1.05 .65 1.00 .90 3.60 benefiting from full production at the taco- half of the plant's output. A decision from Cal- QUARTERLY DIVIDENDS PAID e
- t Full nite mines in its service area. The utility the MPUC is expected by yearepd.
endar Mar.31 Jun.30 Seo.30 Dec.31 Year is booking income from a $330 million This untimely stock is priced expen-2014 transmission line it is constructing in or- sively. The dividend yield is below the 2015 2016
- 5.525 ::5.525 ::5.525 ::5.525 J:5~ 2.08 AdeLrLtEoTimEport power from ManitobbadHydro. uhtility meafn. With t he r ece ntTquotatiopn at s main nonuti1ity su si iaries, t e top o our 20 2 1- 2 0 2 3 arget rice 2017 .535 .535 .535 .535 2.14 ALLETE Clean Energy and U.S. Water Range, total return potential is zero.
2018 .56 .56 Services, are growing rapidly (due in part Paul E. Debbas, CFA June 15, 2018 (A) Diluted EPS. Exel. nonrec. gain (losses): to rounding Next earnings report due early deferred charges. In '17: $11.95/sh. (D) In mill. Company's Financial Strength A
'04, (25¢); '05, ($1.84); '15, (46¢); '17, 25¢; Aug. (B) Div'ds historically paid in early Mar., (E) Rate base: Orig. cost depr. Rate allowed in Stock's Price Stability 95 gain (losses) on disc. ops.: '04, $2.57, '05, June, Sept. and Dec.
- Div'd reinvest. plan MN on com. eq. in '18: 9.25%; earned on avg. Price Growth Persistence 45 (16¢); '06, (2¢), '15 & '16 EPS don't sum due avail. t Shareholder invest. plan avail. (C) Incl. com. eq., '17: 8.0%. Regulatory Climate: Avg.
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wtthout warranties of any kind. -
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscribers own, non-commercial, internal use. No part I of tt may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product:
Earnings Predictability I I' .ll.1!:!lll!'lll!Ull:111111 I
85~-.
18-KCPE-480-RTS
)!~IA[T3 _E_N_E_R~1--.------,:.--...----ll~REC-ENT--.3_9_7§_.1.-IP/E~_1_8__,9_(_rrau...--ing:_1 1
NYSE-LNT PRICE , RATIO , Median:s.2tR_ELAT--.1vE_1_Q!l_oiv 15.0 PIE RATIO , YLD~D l,!0_11 / 0,~_:_' (~ ----1 TIMELINESS Lowered4/l3/1B High: 23.3 21.2 15.8 18.8 22.2 23.8 27.1 34.9 35.4 41.D 45.6 43.5 . Target Price Range SAFETY 2 Raisedg/28/0l r----=t'-"~""~'--~N'-o-s-'-17:...:..5::....i...__:_11:..:..4.!..L.._;10.2
- 0.90 x Dividends p sh 14.6 17.D 20.9 21.9 25.D 27.1 30.4 36.6 36.8 2021 2022 2023 TECHNICAL 1 Raised 6/1/18 divided bi Interest Rate 1--+----+--+-----1---+-----1---+----+--+----+--+-- ---1--+---+-80 BETA .70 (1.00 = Market) 2:f~r:1 ~i/:tivi/Hrce Strength t-+----+--+----t--+----t--+--=---+--+----+--+- ---t--+---t-~g t--""""'20""2.. 1-""2"3"'P"'RO"'J""E""C""T'""11Q"'1N.,.....li--1 o~g~~!/!!a indicates recession --. ~ ::-.*1;,1 * * :.* - - - * * * * * * * * *
- 40 Ann'I Total / ,111 "*11 1....,,..tr,...,....,--t----+---t----+---r---+--t-30 * * * * * * ****
Price Gain Return 1---+--r---+--1----t-__,---,,-r---+-..--+-,,, ..
1 rm,-,.,1"1+'
High 45 (+15%! 7% 25 Low 35 (-10% 1% ,1*, -* _. 1.,,.,,,.,,, ' 20 11 1 Insider Decisions 11 111 " ' l!!!Jnr.':: 111 1111'" 15 A S O N D J F M A *"""" ~ * ""- *I' f;1 1111 11 to Buy O O O O O O O O O * * * * - " ** '1 1,* ** *""* * * **** ****""*... -*- "" ,. .. *'* *** *......... ,......... 10 Options 000000500 toSoll O 1 O O o o O 1 0 1 - - - + - - r - - - + - - r - - - + - - - r - - - + - - + - - - + - - + - - - + - - r - - - + - - l %TOT.RETURN5/18 >---7,5 Institutional Decisions rnrs VLARllH."
3Q2D17 4Q2D17 1Q201B Percent 24 yr. ST~~K l~~E: '.:
lo Buy 194 190 170 shares 16 -+---:-.tn1~"1n'-,--t,,.+-, ,,-;--t--t--,,---l----+---h---:--+.---+,,----,1--,---tt,~--II----I 1 ~
toSoll 187 165 239 traded 8 ~,1, 1 " " *" .I .. " 3yr. 49.2 29.1 >--
Hld'slDDD) 182717. 166325 168237 .JllllJ.llllllllll ll1111111111UIIIIIIII IIIIIIUII 111011111 1111111111 1111111111111111 l11ll 1111111ll1l 1111 5yr. 99.2 67.5 Alliant Energy, formerly called Interstate En- 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUE LINE PUB. LLC , 1-23 ergy Corporation, was formed on April 21, 16.67 15.51 15.40 16.51 13.94 14.77 15.10 14.34 14.58 14.62 15.30 15.55 Revenues per sh 17.75 1998 through the merger of WPL Holdings, 2.28 2.10 2.60 2.75 2.95 3.34 3.44 3.45 3.45 3.97 4.25 4.45 "CashFlow"persh 5.00 IES Industries, and Interstate Power. WPL 1.27 .95 1.38 1.38 1.53 1.65 1.74 1.69 1.65 1.99 2.10 2.25 Earnings per sh A 2.60 stockholders received one share of Inter- .70 .75 .79 .85 .90 .94 1.02 1.10 1.18 1.26 1.34 1.42 Div'd Decl'd per sh e
- t 1.66 state Energy stock for each WPL share, IES i--3"'.9"'8+--5_..,.,43.+--,,3"',9'1i--3"'.0"'3+--,,-,,,;-1---;,-a,,-+----,,=-1---,4"'.25r+--,,-,;;;-+-----,,a-.+-.6'"".75.+-~7...,,
5.22 3.32 3.78 5.26 6.34 1"'"0+-c=ap""*1"":;=-=pe=nd:;,-:in""g7pe:--::-rc.:sh--+--.5"',3;;;--10 stockholders received 1.14 Interstate Ener- 12.78 12.54 13.05 13.57 14.12 14.79 15.54 16.41 16.96 18.08 19.00 20.25 Book Value per sh c 22.85 gy shares for each IES share, and Interstate >-2=2~0_9=0--2=21~.3~1+-2=2~1.7=9--2=22~.0~4+-=~,....._,~=-+~~...,2=26~.9=2-+-===-+-~=-+~23=3~,oo-,,-+-2=3=5,o=o~co_m_m-on-s=;h-1s=
221.97 221.89 221.87 227.67 231.35 01u~ts~t-g-...-+u~2=35~.oo=-'
Power stockholders received 1.11 Interstate 13.4 13.9 12.5 14.5 14.5 15.3 16.6 18.1 22.3 20.6 Bold fig , ....,. Avg Ann'! PIE Ratio 15.0 Energy shares for each Interstate Power .81 .93 .80 .91 .92 .86 .87 .91 1.17 1.01 vatue une Relative P/E Ratio .85 share. 4.1% 5.7% 4.6% 4.3% 4.1% 3.7% 3.5% 3.6% 3.2% 3.1% estlnates AvgAnn'!Div'dYield 4.3%
CAPITAL STRUCTURE as of 3/31/18 3681.7 3432.8 3416.1 3665.3 3094.5 3276.8 3350.3 3320.0 3382.2 3560 3650 Revenues ($mill) 4175 Total Debt $5248.9 mill. Due in 5 Yrs $1500.0 mill. 280.0 208.6 303.9 304.4 337.8 382.1 385.5 373.B 455.9 490 530 Net Profit ($mill) 610 LT Debt $4056.8 mill. LT Interest $180.0 mill.
(LT interest earned: 4.0x) 33.4% -- 30.1% 19.0% 21.5% 12.4% 10.1% 13.4% 12.5% 12.0% 12.0% Income Tax Rate 12.0%
-- -- -- -- -- 7.0% 7.3% 7.5% 7.5% AFUDC %to Net Profit 7.5%
Pension Assets-12/17 $950.7 mill. Oblig. $1303.1 36.3% 44.3% 46.3% 45.7% 48.4% 46.1% 49.7% Yo 52.8% 49.0% 50.0% 50.0% Long-Term Debt Ratio 50.0%
mill. 58.6% 51.2% 49.5% 50.9% 48.4% 50.8% 47.5% Yo 47.2% 51.0% 50.0% 50.0% Common Equity Ratio 50.0%
Pfd Stock $400.0 mill. Pfd Div'd $10.2 mill. 4815.6 5423.0 5840.B 5921.2 6476.6 6461.0 7257.2 8177.6 8192.B 8300 8400 Total Capital ($mill) 8700 16,000,000 shs.
5353.5 6203.0 6730.6 7037.1 7838.0 7147.3 6442.0 9809.9 10797.9 11125 11645 Net Plant ($mill) 12900 Common Stock 231,481,828 shs. 7.0% 5.1% 6.6% 6.4% 6.3% 7.0% 6.3% 6.3% 5.6% 5.6% 6.0% 6.5% Return on Total Cap'! 7.0%
9.1% 6.9% 9.7% 9.5% 10.1% 11.0% 10.6% 10.2% 9.7% 10.9% 11.0% 11.0% Return on Shr. Equity 11.5%
9.3% 6.8% 9.9% 9.5% 10.3% 11.3% 10.9% 10.2% 9.7% 10.9% 11.0% 11.0% Return on Com Equity E 11.5%
MARKET CAP: $9.2 billion (Large Cap) 3.8% .9% 3.8% 3.3% 3.9% 4.9% 4.3% 3.6% 2.8% 4.0% 4.0% 4.0% Retained to Com Eq 4.0%
ELECTRIC OPERATING STATISTICS 62% BB% 64% 67% 64% 57% 59% 65% 72% 63% 64% 63% All Div'ds to Net Prof 64%
2015 2016 2 ~~~ i--e'"'us.,.,1-:-:N"="~sccs:-:-A.,,.lli~an_t..,E,...ne-rg~y-C-o-rp-.~.f,....or_m_e...,.rly~n-a_m_e...,.d~ln-te-rs-ta-te~En-e-~~s-o-ur-ce-s~.-20_1_7:-co~al-,4-0-%~;-ga_s_,-17~%-,;-o-th-e-r,-4""'3%.,.,.-=F=-u""'el_c_o~st-s:-4-5°-V.-t
%Change Retail Sales (KWH) -.1 +2.0 Avg. Indus!.. Use (M'Mll 11735 11987 12102 gy, is a holding company formed through the merger of WPL Hold- of revs. 2017 depreciation rate: 5.5%. Estimated plant age: 15 Avg. Indus!. Revs1er KWti (¢) 6.92 7.04 7.16 ings, IES Industries, and Interstate Power. Supplies electricity, gas, years. Has approximately 3,989 employees. Chairman & Chief Ex-Capacity al Peak (MIIJ, 5385 5615 ~~~~ and other services in Wisconsin, Iowa, and Minnesota. Elect. revs. ecutive Officer: Patricia L Kampling. Incorporated: Wisconsin. Ad-Peak load, Summer!~) 5385 5615 Annual Loadfactor(Y,) NA NA NA by state: WI, 38%; IA, 61 %; MN, 1%. Elect. rev.: residential, 36%; dress: 4902 .N. Biltmore Lane, Madison, Wisconsin 5371 B. Tele-
%Change Customers (yr-£nd) +.3 +1.0 +.4 commercial, 24%; industrial, 30%; wholesale, 8%; other, 2%. Fuel phone: 608-458-3311. Internet: www.alliantenergy.com.
t-----------------------------
We think Alliant Energy's earnings the
1 F~ed Charge Gov.(%) 315 295 319 IUB is expected in around 10 months.
ANNUAL RATES Past Past Est'd '15-'17 will advance steadily in 2018 and Regulators have approved another of change (per sh) 10 Yrs. 5Yrs. to '21-'23 2019. Each year, the utility is expected to 500 megawatts of wind energy expan-Revenues .5% -1.5% 3.5% benefit from electric and gas rate increases sion for Alliant. Combined with ongoing "Cash Flow 3.5o/, 6.5% 7.0% at Interstate Power and Light (IPL) and projects in western Iowa, the company ex-Earnings 5.0% 6.5% 6.5%
Dividends 7.5% 6.5% 6.0% Wisconsin Power and Light (WPL). At the pects to add 1,000 megawatts of wind en-Book Value 4.0% 4.5% 5.0% start of 2018, electric tariffs were boosted ergy by 2020, bringing its total renewable Cal- QUARTERLY REVENUES ($ mill.) by $130 million (11.6%), while gas rates energy mix in that state to at least 30%.
Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year are now in the process of being hiked (see Progress continues at the West River-2015 897.4 717.2 898.9 740.1 3253.6 below). Our 2018 share-net estimate side Energy Center. The 730 megawatt 2016 843.8 754.2 925.0 797.0 3320.0 ($2.10) is near the midpoint of manage- facility is approximately one-third com-2017 853.9 765.3 906.9 856.1 3382.2 ment's targeted guidance range of $2.04- plete and is on track to be placed into serv-2018 916.3 790 1050 803.7 3560 $2.18. For 2019, we envision earnings of ice by early 2020. The plant will power 2019 935 815 1025 875 3650 $2.25 a share, representing year-on-year nearly 500,000 homes upon completion.
Cal- EARNINGS PER SHARE A Full growth of around 7%. The company has some financing endar Mar.31 Jun.30 Sep.30 Dec.31 Year The company's largest utility subsidi- needs. Alliant plans to issue $1 billion of 2015 .44 .30 .80 .15 1.69 ary has filed a rate case. Interstate long-term notes this year to help fund its 2016 .43 .37 .57 .28 1.65 Power and Light is asking the Iowa Utili- construction projects and refinance $595
.2017 .44 .41 .73 .41 1.99 ties Board for an annual gas increase of million of term loans that are coming due 2018 .52 .43 .82 .33 2.10 $19.8 million (8.0%), based on a return of this year. The utility also said it would is-2019 .54 .45 .88 .38 2.25 9.8% on a common-equity ratio of 49.6%. sue up to $200 million in equity in 2018 .
Cal- QUARTERLY DIVIDENDS PAID e -t Full An interim hike of approximately $11.3 This neutrally ranked stock has a div-endar Mar.31 Jun.30 Seo.30 Dec.31 Year million went into effect last month while idend yield that is about equal to the 2014 .255 .255 .255 .255 1.02 the IUB debates the proposal. Alliant has average for a utility. In addition, with 2015 .275 .275 .275 .275 1.10 said that the tariff is needed to cover natu- the recent price well within our 2021-2023 2016 .295 .295 .295 .295 1.18 ral gas improvements made over' the past Target Price Range, total return potential 2017 .315 .315 .315 .315 1.26 six years. A formal hearing should take is subpar.
place in the fall and a final decision from Daniel Henigson, CPA June 15, 2018 2018 .335 .335 (A) Diluted EPS. Exel. nonrecur. gains (losses): Aug., and Nov.
- Div'd reinvest. plan avail. t Orig. cost. Rates all'd on com. eq. in IA in '17:
'08, 4¢; '09, (44¢); '10, (8¢); '11, (1¢); '12, (8¢). Shareholder invest. plan avail. (C) Incl. 10.5%; in WI in '17 Regul. Clim.: WI, Above I Company's Financial Strength Stock's Price Stability
- 100 A
Next earnings report due early August. (B) deferred chgs. In '17: $69.7 mill., $0.30/sh. (D) Avg.; IA, Avg. Price Growth Persistence 90 Dividends historically paid in mid-Feb., May, In millions, adjusted for split. (E) Rate base: EamJngs Predictability_ ___ __ __ 85-*
© 2018 Value Line, Inc. All nghts reserved. Factual material is obtained 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 subscriber's own, non-commercial, inlemal use. No part:
of 1t may be reproduced, resold, stored or transmitted in any printed, electronic or othar form, or used for generating or marketing any printed or electronic publication, service or product.
18-KCPE-480-RTS I-A_M_f_Bg[----,---.------,----,--1'--r-REC-ENT_!7_4~11P/E~1!!(_Tra~iling NYSE-AEE PRICE , RATIO , Median:_: 19_.a)J.--RELA-Jl 15.0 P/E RATIO ~VE1~!D_IV'D~1~3____i.;::0/o~_
, YLD /( ' .- -
~- - - - I TIMELINESS 2 Raised 3/2/lB High: 55.0 54.3 35.3 29.9 34.1 35.3 37.3 48.1 46.8 54.1 64.9 59.8
- Target Price Range Raised6/20/14 -t-~~-~N~D_S_47_._1~-25_._5..........,19.5 23.1 25.5 28.4 30.6 35.2 37.3 41.5 51.4 51.9 2021 2022 2023 SAFETY 2 - 0.64 x Dividends p sh TECHNICAL 2 Raised6/15/18 .... i~i~ii~eb~r/~!effi~!n,~e t--+----+--+----+--+---+---+----+---+----+---+ ---+---+----80 0o,.=,...M,.,ar1<.,.e"'t).,...n..----;
t-8-E-TA..,.,.,.Br.r5-,....(1.,,. o~~~~~/i'!a indicates recession /'-. "' ' ,, .. :.; ***** * **** ~~
.:u.:*1-23 l"~UJC\, IIU!ll)
Price Gain
~~s:::::7.f2311if:=:--t---t::::;;;.,./'9----::--r AnR~tJ~al ****~~"-*""-**.Ii "--
. .~~\F"i~~~,.,.'4rtl'*'4l*'!lj"F-"----jf-...:.**:.:-+~:-:-::f:-:--+--f--+--l-40 1..,.-/ 11 ,.,.,,, .. * 11111 ,,., --- ** 30 110 High 65 (+15%l 7% r I* .. I I'"' 'T' 25 11
~L~o~w~_:5~0~J,(-~1~5~%L_!.1~%~l--,---i----t*.,_1i:.:=..:;t-"-:'--t--::;;t-:::-""t--t----t-----i-:-----t-----ii----t-- -i----t-----ii---r20 Insider Decisions l---t---t---+---*+-*.,_ * .,,**c.."*-*-1=....=-:*_*"t=""-'"-"..:;'":.,p*-.,..-1=---:*--:""'":....:':::**".c.""'-.I..--.":..*.:.*f-a:--+---t---+---t---+-15 IIM ASONDJFMA ....- ........................... ..**
toBuy ooooooo oo 10 Options o o o o 0211151 tos,n Institutional o o oDecisions 1 o o o 4 o i---+--1+-l1-1,-,11-11-l1+-1ll-l1_111_1l-11+----+--+----+--t----+-- --11----+---t----+----t %TOT.RETURN5/18THIS VLARITH: ..-7.5 3Q2017 4Q2017 1Q2018 Percent, 1~- . . . STOCK INDEX _
to Buy 229 212 234 shares 10 ~ 1 yr. 7.6 14.3 _
toSell 215 192 243 traded 5 fll"'t---+----l 3yr. 63.4 29.1 _
Hld's(000) 186752 171005 170335 1111 5 yr. 110.1 67.5 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 19 VALUELINEPUB.LLC;,1-23 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 25.13 25.04 25.46 26.45 27.10 Revenues per sh 29.50 5.28 6.29 5.57 6.10 6.02 6.76 6.44 6.06 6.33 5.87 5.87 5.25 5.77 6.08 6.59 6.80 7.40 7.90 "Cash Flow" per sh 9.50 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 2.38 2.68 2.77 3.05 3.25 Earnings per sh A 4.00 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 1.66 1.72 1.78 1.85 1.94 Div'd Decl'd per sh e
- 2.35 5.11 4.19 4.13 4.63 4.99 6.96 9.75 7.51 4.66 4.50 5.49 5.87 7.66 8.12 8.78 9.05 9.80 11.25 Cap'I Spending per sh 9.50 24.93 26.73 29.71 31.09 31.86 32.41 32.80 33.08 32.15 32.64 27.27 26.97 27.67 28.63 29.27 29.61 31.00 32.50 Book Value per sh c 37.50 154.10 162.90 195.20 204.70 206.60 208.30 212.30 237.40 240.40 242.60 242.63 242.63 242.63 242.63 242.63 242.63 244.00 245.50 Common Shs Outst'g O 250.00 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 17.5 18.3 20.6 Bold fig res are Avg Ann'I PIE Ratio 14.5
.86 .77 .86 .89 1.05 .92 .85 .62 .62 .75 .85 .93 .88 .88 .96 1.02 Value Une Relative P/E Ratio .80 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% 4.0% 3.5% 3.1% estln ates Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUCTURE as of 3131118 7839.0 7090.0 7638.0 7531.0 6828.0 5838.0 6053.0 6098.0 6076.0 6177.0 6450 6650 Revenues ($mill) 7400 Total Debt $8896 mill. Due in 5 Yrs $3338 mill. 615.0 624.0 669.0 602.0 589.0 518.0 593.0 585.0 659.0 683.0 755 810 Net Profit ($mill) 1000 LT Debt $6766 mill. LT Interest $348 mill. 33.7% 34.7% 36.8% 37.3% 36.9% 37.5% 38.9% 38.3% 36.7% 38.2% 22.0% 22.0% Income Tax Rate 22.0%
(LT interest earned: 4.3x)
Leases, Uncapitalized Annual rentals $10 mill. 4.6% 5.8% 7.8% 5.6% 6.1% 7.1% 5.7% 5.1% 4.1% 3.5% .4.0% 4.0% AFUDC %to Net Profit
- 3.0%
Pension Assets-12/17 $4293 mill. 47.8% 49.7% 48.2% 45.3% 49.5% 45.2% 47.2% 49.3% 47.7% 49.2% 49.5% 49.0% Long-Term Debt Ratio 49.0%
Oblig $4827 mill. 50.8% 49.1% 50.9% 53.7% 49.4% 53.7% 51.7% 49.7% 51.3% 49.8% 49.5% 50.0% Common Equity Ratio 50.0%
Pfd Stock $142 mill. Pfd Div'd $6 mill. 1---,=c+-===-i--.c=+-c~-=-+-~~1--,-,=-+-=-=-+--,=-,~+-c~c-f-~=--1-1.,..,5,:-,22cc5+-1"'5 13712 15991 15185 14738 13384 12190 12975 13968 13840 14420 9:--a5c=-o-1-aT,..,ot""a1'"'c~ap~it,..;al~($""m~il ~)--+-"'18=10""0,-1 807,595 sh. $3.50 to $5.50 cum. (no par), $100 16567 17610 17853 18127 16096 16205 17424 18799 20113 21466 22800 24425 Net Pl ant ($ m1'II) 27900 stated val., redeem. $102.176-$110/sh.; 616,323 sh. 4.00% to 6.625%, $100 par, redeem. $100- 5.7% 5.3% 6.0% 5.6% 6.0% 5.6% 5.8% 5.3% 6.0% 5.9% 6.0% 6.0% Return on Total Cap'I 6.5%
$104/sh. 8.6% 7.8% 8.5% 7.5% 8.7% 7.7% 8.7% 8.3% 9.1% 9.3% 10.0% 10.0% Return on Shr. Equity 10.5%
Common Stock 243,653,807 shs. as of 4130/18 8.7% 7.8% 8.6% 7.5% 8.8% 7.8% 8.7% 8.3% 9.2% 9.4% 10.0% 10.0% Return on Com Equity E 10.5%
MARKET CAP: $14 billion (Large Cap) 1.0% 3.5% 3.8% 2.8% 3.0% 1.9% 2.9% 2.5% 3.3% 3.4% 4.0% 4.0% Retained to Com Eq 4.5%
88% 56% 56% 63% 66% 76% 67% 70% 64% 64% 60% 59% All Div'ds to Net Prof 59%
ELECTRIC OPERATING STATISTICS
%Change Retail Sales (KWH) 2015 2016 2017
-1.1 -4.2 _34 _ t-----.......
BUSINESS: ----~---'---~---'---'---~~-'---~--'---~--'--~-----~----1 Ameren Corporation is a holding company formed dustrial, 8%; other, 11 %. Generating sources: coal, 71 %; nuclear, Avg. Indus!. Use (MWH) NA NA NA through the merger of Union Electric and CIPSCO. Acq'd CILCORP 19%; hydro & other, 4%; purchased, 6%. Fuel costs: 27% of revs.
Avg. Indus!. Revs.Jer KW!l (¢) NA NA NA 1/03; Illinois Power 10/04. Has 1.2 mill. electric and 127,000 gas '17 reported deprec. rates: 3%-4%. Has 8,600 employees. Chair-Capaci~ al Peak (MW) NA NA ~~ customers in Missouri; 1.2 mill. electric and 813,000 gas customers man, President & CEO: Warner L. Baxter. Inc.: MO. Address: One Peak Load, Summer !Mw) NA NA NA in Illinois. Discontinued nonregulated pol'/er-generation operation in Ameren Plaza, 1901 Chouteau Ave., P.O. Box 66149, St. Louis, AnnualloadFactor(Y,) NA NA
%Change Customers (yr-en~ NA NA NA '13. Electric rev. breakdown: residential, 46%; commercial, 35%; in- MO 63166-6149. Tel.: 314-621-3222. Internet: www.ameren.com.
F~edChargeCov.(%) 343 351 362 We esthnate that Ameren will post a will increase the ability of utilities to earn strong earnings increase in 2018. Posi- a reasonable return on their investments.
ANNUAL RATES Past Past Est'd '15-'17 of change (per sh) 10 Yrs. 5Yrs. to '21-'23 tive factors include a full year's effect of It will also encourage utilities to increase Revenues -3.0% -3.5% 2.5% the rate increase the utility received in their capital spending. As a result, "Cash Flow" .5% 1.5% 6.5% Missouri last April; spending on Ameren's Ameren plans to initiate a project (roughly Earnings -1.0% .5% 7.5%
Dividends -4.0% 2.0% 5.5% electric transmission system; and winter $1 billion through 2023) to modernize the Book Value -1.0% -1.0% 4.5% weather that was much colder than a year electric grid. This should boost the compa-QUARTERLY REVENUES ($ mill.) earlier. Our estimate is at the midpoint of ny's long-term earnings growth rate. Man-Cal- Full agement will likely provide more informa-endar Mar.31 Jun.30 Sep.30 Dec.31 Year Ameren's guidance of $2.95-$3.15 a share.
Ameren filed a gas rate application in tion with its earnings call for the third or 2015 1556 1401 1833 1308 6098.0 2016 1434 1427 1859 1356 6076.0 Illinois. The utility is seeking a rate in- fourth quarter of 2018.
2017 1514 1538 1723 1402 6177.0 crease of $44 million, which incorporates Ameren is planning to acquire a 400- .
2018 1585 1600 1765 1500 6450 agreements with the staff of the Illinois megawatt wind farm. This is part of the 2019 1650 1650 1800 1550 6650 commission for a 9.87% return on equity company's potential $1 billion of wind gen-EARNINGS PER SHARE A and a common-equity ratio of up to 50%. eration investments by 2020. The Missouri Cal- Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year An order is expected in December, with commission must approve this proposed 2015 .45 .40 1.41 .12 2.38 new tariffs taking effect in January. acquisition. An associated transmission 2016 .43 .61 1.52 .13 2.68 We look for another strong earnings project is already under construction. This 2017 .42 .79 1.18 .39 2.77 increase in 2019. Additional transmis- is expected to cost $250 million and be in 2018 .62 .63 1.40 .40 3.05 sion spending and rate relief in Illinois service in December of 2019 .
2019 .60 .70 1.50 .45 3.25 should help. Our $3.25-a-share estimate This thnely stock has a dividend yield QUARTERLY DIVIDENDS PAID e
- would produce profit growth of 7%, which that is slightly below the. utility mean.
Cal- Full endar Mar.31 Jun.30 Seo.30 Dec.31 Year is at the top end of Ameren's annual goal Although we have raised our sights for the of 5%-7%. 3- to 5-year period, with the recent price 2014 .40 .40 .40 .41 1.61 within our 2021-2023 Target Price Range, 2015 .41 .41 .41 .425 1.66 A new regulatory law in Missouri will 2016 .425 .425 .425 .44 1.72 help utilities in the state. Regulatory total return potential over that time frame 2017 .44 .44 .44 .4575 1.78 lag there has been a problem historically, is unspectacular.
2018 .4575 but the new law (effective August 28th) Paul E. Debbas, CFA June 15, 2018 (A) Dil. EPS. Exel. nonrec. gain (losses): '05, ing. Next egs. report due early Aug. (B) Div'ds depr. Rate all'd on com. eq. in MO in '17: elec., Company's Financial Strength A (11¢); '10, ($2.19); '11, (32¢); '12, ($6.42); '17, histor. paid in late Mar., June, Sept., & Dec.
- none spec.; in '11: gas, none spec.; in IL in '14: Stock's Price Stability 95 (63¢); gain (loss) from disc. ops.: '13, (92¢); Div'd reinv. plan avail. (C) Incl. intang. In '17: elec., 8.7%, in '16: gas, 9.6%; earned on avg. Price Growth Persistence 40
'15, 21¢. '16-'17 EPS don't sum due to round- $6.76/sh. (D) In mill. (E) Rate base: Orig. cost com. eq., '17: 9.3%. Reg. Climate: Below Avg.
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wtthout warranties of any kind.'
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part, Earnings Predictability 111-,111~~ ... 1,,...., :11Ill'lll!lllllll*rn1 1.-.
80*-* .
I*
of tt may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product:
IJvUvUUH, rU.J.'U - J 18-KCPE-480-RTS AMERICAN ELEC. PWR. NYSE-AEP l~~f!fl 65 ,29 IP/ERATIO 17,0 Median: 18.1) crailing: 14.0 RElATIVE PIE RATIO o93 I IDIV'D YLD 3.9%
....... =-
TIMELINESS 4 Lowered 514118 High: 51.2 49.1 36.5 37.9 41.7 45.4 51.6 63.2 65.4 71.3 78.1 73.4 - Target-Price Range Low: 41.7 25.5 24.0 28.2 33.1 37.0 41.8 45.8 52.3 56.8 61.8 63.3 2021 2022 2023 SAFETY 1 Raised3/17117 -
LEGENDS 0.67 x Dividends p sh 128 TECHNICAL 3 Raised 5/25118 . . . . ~~i~r~eb~r/gleffi~ln,~e BETA .65 (1.00 = Market) 96 80 o~~~~:/i~a indicates recession ,,;-- ,_,_,.,,111 11
,:u,n-i3 IIVN;) 64 Price Gain Ann'I Total Return .. ,* .... 11.11
- ./
1111"'
,,**I' 1111111*11 48
,1*11 High 80 (+25%l 9% 40
'h *
- rff'i"':'1'1"11 *11 1**1h*
- 1 .....
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Insider Decisions
... *.... ***.. ....** ...-... .......... ...* 24 A S O N D J FM A to Buy 0 0 0 0 0 0 0 0 0 Options 0 0 0 0 0 0 0 0 0
- -*. --. .........**** 16 to Sell 0 0 0 0 0 0 0 0 0 -12
% TOT. RETURN 5/18 Institutional Decisions MIiii l1m1~111~~11~11 ~~!1~111~~11~1111~~~~11~1~~~~11ll~La THIS VLARITH.'
3Q2017 4Q2017 1Q2018 Percent ,I I STOCK INDEX 15-to Buy 388 371 406 shares 10 1 yr. -1.9 14.3 to Sell 351 342 468 traded 5 3yr. 34.5 29.1 Hld'sfOOOf 382879 352776 357126 5yr. 78.8 67.5 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2019 "'VALUE LINE PUB. LLC , 1-23 42.96 36.82 35.51 30.76 31.82 33.41 35.56 28.22 30.01 31.27 30.77 31.48 34.78 33.51 33.31 31.35 32.00 32.85 Revenues per sh 34.50 6.99 5.76 5.89 5.96 6.67 6.80 6.84 6.32 6.29 6.83 6.92 7.02 7.57 7.98 8.47 7.95 8.45 8.90 "Cash Flow" per sh 10.25 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 3.59 4.23 3.62 3.85 4.10 Earnings per sh A 5.00 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 2.39 2.51 2.63 Div'd Decl'd per sh B
- 3.05 5.08 3.44 4.28 6.11 8.89 8.88 9.83 6.19 5.07 5.74 6.45 7.75 8.68 9.37 9.98 11.79 12.50 12.95 Cap'I Spending per sh 11.25 20.85 19.93 21.32 23.08 23.73 25.17 26.33 27.49 28.33 30.33 31.37 32.98 34.37 36.44 35.38 37.17 38.60 40.20 Book Value per sh c 46.50 338.84 395.02 395.86 393.72 396.67 400.43 406.07 478.05 480.81 483.42 485.67 487.78 489.40 491.05 491.71 492.01 493.50 495.00 Common Shs Outst'g u 516.00 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 15.B 15.2 19.3 a*oldflg res are Avg Ann'I P/E Ratio 14.5
.69 .61 .66 .73 .70 .87 .79 .67 .85 .75 .88 .81 .84 .BO .BO .96 Value Line Relative P/E Ratio .80 estln ates 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% 3.8% 3.5% 3.4% Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUCTIJRE as of 3/31/18 14440 13489 14427 15116 14945 15357 17020 16453 16380 15425 15800 16250 Revenues ($mill) 17750 Total Debt $24121 mill. Due In 5 Yrs $10714 mill. 1208.0 1365.0 1248.0 1513.0 1443.0 1549.0 1634.0 1763.4 2073.6 1783.2 1850 1970 Net Profit ($mill) 2465 LTDebt$18845mill. LT Interest $777 mill. 31.3% 29.7% 34.8% 31.7% 33.9% 36.2% 37.8% 35.1%
Incl. $1410.5 mill. securitized bonds. Incl. $294 26.8% 33.7% 19.0% 19.0% Income Tax Rate 19.0%
mill. capitalized leases. 9.9% 10.9% 10.4% 10.6% 11.2% 7.3% 9.0% 11.0% 8.0% 8.0% 11.0% 10.0% AFUDC %to Net Profrt 6.0"/o (LT interest earned: 3.8x) 59.1% 54.4% 53.1% 50.7% 50.6% 51.1% 49.0% 49.8% 50.0% 51.5% 52.5% 54.5% Long-Tenn Debt Ratio 50:5%
Leases, Uncapitalized Annual rentals $245.9 mill. 40.7% 45.4% 46.7% 49.3% 49.4% 48.9% 51.0% 50.2% 50.0% 48.5% 47.5% 45.5% Common Equity Ratio 49.5%
Pension Assets-12/17 $5174.1 mill. 26290 28958 29184 29747 30823 32913 33001 35633 34775 37707 40275 43750 Total Capital ($mill) 48700 Oblig $5215.8 mill. 32987 34344 Pfd Stock None 35674 36971 38763 40997 44117 46133 45639 50262 54150 58175 Net Plant ($mill) 67600 6.2% 6.2% 5.7% 6.6% 6.1% 6.0% 6.3% 6.1% 7.2% 5.9% 5.5% 5.5% Return on Total Cap'I 6.0%
Common Stock 492,523,470 shs. 11.2% 10.3% 9.1% 10.3% 9.5% 9.6% 9.7% 9.9% 11.9% 9.8% 10.0% 10.0% Return on Shr. Equity 10.5%
as of 4/26/1 B 11.3% 10.4% 9.1% 10.3% 9.5% 9.6% 9.7% 9.9% 11.9% 9.8% 10.0% 10.0% Return on Com Equity E 10.5%
MARKET CAP: $32 billion (Large Cap) 5.1% 4.6% 3.1% 4.2% 3.5% 3.7% 3.8% 3.9% 5.5% 3.2% 3.5% 3.5% Retained to Com Eq 4.0"/o ELECTRIC OP.ERATING STATISTICS 55% 56% 66% 60% 63% 62% 61% 60% 54% 67% 67% 66% All Div'ds to Net Prof 63%
2015 2016 2017 BUSINESS:
%Cha~e Retail Sales (Kl'Af) -1.2 +.3 -1.6 American Electric Power Company, Inc. (AEP), Pipeline '05; commercial barge operation in '15. Generating Avg. In ust. Use (MWH~ NA NA NA through 1Ooperating utilities, serves 5.4 mill. customers in Arkan- sources not available. Fuel costs: 34% of revenues. '17 reported Avg.lndust.Revsi (¢) NA NA NA sas, Kentucky, Indiana, Louisiana, Michigan, Ohio, Oklahoma, Ten- depreciation rates (utility): 1.6%-9.2%. Has 17,700 employees.
CapacifyatPeak ) NA NA NA nessee, Texas, Virginia, & West Virginia. Electric revenue break- Chairman, President & CEO: Nicholas K. Akins. Incorporated: New Peakloadt) NA NA NA Annual Loa Factor(%& NA NA NA down: residential, 40%; commercial, 23%; _industrial, 19%; whole- York. Address: 1 Riverside Plaza, Columbus, Ohio_ 43215-2373.
%Change Cu~omers r-en~ +.3 NA NA sale, 15%; other, 3%. Sold SEEBOARD (British utility) '02; Houston Telephone: 614-716-1000. Internet: www.aep.com.
F~ed Charge Cov. (%) 356 374 354 We estimate that American Electric well. The 2,000-megawatt facility would ANNUAL RATES Past Past Est'd '15-'17 Power's earnings will increase nicely cost $4.5 billion and is targeted for comple-of change (per sh) 10Yrs. 5Yrs. to '21-'23 in 2018 and 2019. As usual, AEP is bene- tion in the fourth quarter of 2020. This Revenues -- 1.5% 1.0% fiting from rate relief. So far this year, the project is not reflected in AEP's capital "Cash Flow 2.5% 4.0% 4.0% company's utilities in Michigan, Kentucky, budget, or in our figures.
Earnings 3.0% 5.5% 4.5%
Dividends 4.0% 4.5% 5.0% Oklahoma, and Texas have been granted Rate cases are pending in Indiana and Book Value 4.0% 4.0% 4.0% tariff increases. Other rate cases are pend- West Virginia. Indiana & Michigan Cal- QUARTERLY REVENUES ($ mill.) ing (see below). AEP's extensive electric Power reached a settlement (subject to Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year transmission system obtains revenues an- regulatory approval) for a rate hike of $97 2015 4580 3827 4431 3615 16453 nually for $3 billion in capital spending. million, based on a 9.95% return on equity.
2016 4045 3893 4652 3790 16380 Moreover, the utilities are experiencing New tariffs are expected to take effect at 2017 3933 3577 4105 3810 15425 some load growth, thanks to the improving the start of July. Appalachian Power is as-2018 4048 3652 4200 3900 15800 economies in their service territories. Our king the West Virginia commission for an 2019 4150 3750 4350 4000 16250 2018 and 2019 share-earnings estimates increase of $115 million, based on a Cal- EARNINGS PER SHARE A Full are at the midpoint of the company's tar- 10.22% ROE. New rates should take effect endar Mar.31 Jun.30 Sep.30 Dec.31 Year geted ranges of $3.75-$3.95 and $4.00- by March. Another petition might well oc-2015 1.27 .88 1.04 .41 3.59 $4.20, respectively. Management's goal for cur in Oklahoma, where Public Service of 2016 1.02 1.03 1.43 .76 4.23 yearly profit growth is 5%-7%, and our es- Oklahoma was disappointed with the rul-2017 .94 .76 1.11 .81 3.62 timates, if attained, would produce in- ing it received earlier this year. Cost-2018 .92 .85 1.23 .85 3.85 creases within this range. control measures have become even more 2019 1.00 .90 1.30 .90 4.10 AEP is proposing a huge wind project important here in view of this.
Cal- QUARTERLY DIVIDENDS PAID 8 * ,Full that would serve four states. Although This high-quality stock is untim.ely, endar Mar.31 Jun.30 Seo.30 Dec.31 Year there has been some opposition, the but offers an attractive dividend 2014 .50 .50 .50 .53 2.03 project has been approved in Arkansas, yield. This is about a half percentage 2015 .53 .53 .53 .56 2.15 and the utilities in Louisiana and Oklaho- point above the utility mean. Total return 2016 .56 .56 .56 .59 2.27 ma have reached regulatory settlements potential to 2021-2023 is somewhat above 2017 .59 .59 .59 .62 2.39 that await commission approval. The average for this industry.
2018 .62 .62 Texas regulators must have their say, as Paul E. Debbas, CFA June 15, 2018 (A) Dil. EPS. Exel. nonrec. gains (losses): '03, (32¢); '04, 15¢; '05, 7¢; '06, 2¢; '08, 3¢; '15,
- Div'd reinv. plan avail. (C) Incl. intang. In '17: Companls Financ_i~I Strength A+
($1.92); '04, 24¢; '05, (62¢); '06, (20¢); '07, 58¢; '16, (1¢). '15!16 EPS don't sum due to $12.59/sh. (D) In mill. (E) Rate base: vanous. Stock's rice Stability 100 (20¢); '08, 40¢; '10, (7¢); '11, 89¢; '12, (38¢); rounding. Next egs. report due fate July. Rates all'd on com. eq.: 9.3%-10.9%; earn. on Price Growth Persistence 50
'13, (14¢); '16, ($2.99); '17, 26¢; disc. ops.: '03, (BJ Div'ds paid early Mar., June, Sept., & Dec. avg. com. eq., '17: 10.0%. Regul. Climate: Avg. Earnings Predictability 85 * .
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wtthout wananties of ani kind., - *,
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, intemal_use. o part*, I I I ' *
- 11 I*
of tt may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generatin or marketing an y printed or electronic publication, service or product:
- L.JvHvUUH, r-1..l.l'-.1 - J 18-KCPE-480-RTS --
76 ,23 IP/ERATIO 17, gerailing:18.2) RELATIVE 101 DIV'D CON. EDISON NYSE-ED High: 52.9 49.3 46.3 IRECENT PRICE 51.0 62.7 66.0 64.0 Median:
68.9 15.0 P/E RATIO 72.3 81.9 I
89.7 YLD 3.8%111 84.9 Target Price Range TIMELINESS 3 Raised 312/18 Low: 43.1 34.1 32.6 41.5 48.6 53.6 54.2 52.2 56.9 63.5 72.1 73.7 2021 2022 2023 SAFETY 1 New 7/27/90 LEGENDS 120 100 TECHNICAL 4. Raised 5/18118
.50 (1.00 = Market)
- ~i~i~:d ~vi1~,~~!sr ~~le
...
- Relative ~rice Strength 0 ,
1111
- 1 111 ---- *****
.... ---- . 80 BETA
~t~~:/:,~a indicates recession _...(,'j'il* ....
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"(11**1,11,11, 111111111"
- II* 64
.tU~l-23 l't(UJt:\, IIUNl:l
.... 48
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Ann'I Total 1,1* 1 1 *11
...... It*p1*1**
Price Gain Return 32 High Low 85 (+10%l 70 *(-10%
7%
2% *-* *....***** ... .... ...........
~
24 20 Insider Decisions J A SO ND J F M -** 16 to Buy 11 8 811 8 811 8 8 12 Options 0 0 0 2 2 0 812 0 to Soll 0 1 0 0 0 0 0 0 1 % TOT. RETURN 4/18 -8 Institutional Decisions THIS VLAR!TH."
2Q2017 3Q2017 4Q2017 Percent 21 ,I I 1 yr.
STOCK 4.6 INDEX 9.5 I-
- ~:~ri 330 323 335 322 298 shares 284 traded 14 1,,,,11, ,..
II II. 3yr. 45.4 25.8 rr Hld'slDOO) 196270 197384 178532 2002 2003 2004 2005 2006 2007 7
11~~~[1111~~~~1111~~~~1 1111111111 11111111111 2011 2012 2014 2015 2016 2017 2018 2019 II IIIIIIIIU Ill 5yr. 53.1 68.8
© VALUE LINE PUB. LLC , 1-23 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 42.85 39.59 38.82 38.80 39.80 Revenues per sh 43.25 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 7.93 7.89 8.41 8.75 9.15 "Cash Flow" per sh 10.50 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 4.05 3.94 4.10 4.25 4.40 Earnings per sh A 4.75 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 2.76 2.86 2.96 Div'd Decl'd per sh e
- 3.30 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 10.42 12.07 11.11 12.50 11.15 Cap'I Spending per sh 11.25 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 44.55 46.88 49.74 51.70 53.25 Book Value per sh c 58.00 213.93 225.84 242.51 245.29 257.46 272.02 273.72 281.12 291.62 292.89 292.87 292.87 292.88 293.00 305.00 310.00 317.00 318.00 Common Shs Outst'g 0 321.00 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 15.6 18.8 19.8 Bold fig res are Avg Ann'I P/E Ratio 16.5
.83 '.95 .98 .83 .84 .79 .99 .99 Value Lin* Relative P/E Ratio .90
.73 .82 .96 .80 .84 .73 .74 .85 ostfn ~OS 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% 4.1% 3.6% 3.4% Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUCTURE as of 3/31/18 13583 13032 13325 12938 12188 12381 12919 12554 12075 12033 12300 12650 Revenues ($mill) 13850 Total Debt $17410 mill. Due in 5 Yrs $4935 mill. 933.0 868.0 992.0 1062.0 1141.0 1157.0 1066.0 1193.0 1189.0 1266.0 1340 1405 Net Profit ($mill) 1550 LT Debt $14730 mill. LT Interest $670 mill. 36.0% 34.2% 36.0% 36.1% 34.5% 31.8% 34.0% 33.6% 35.3% 36.6% 21.5% 21.5% Income Tax Rate 21.5%
(LT interest earned: 3.6x) 1.5% 2.0% 1.0% AFUDC %to Net Profit 1.0%
1.7% 2.6% 2.4% 1.6% .5% .5% .3% .7% 1.3%
Leases, Uncapitalized Annual rentals $63 mill. 48.3% 48.5% 48.6% 46.5% 45.9% 46.1% 48.0% 47.9% 50.8% 48.9% 49.0% 48.5% Long-Term Debt Ratio 48.5%
50.6% 50.4% 50.4% 52.5% 54.1% 53.9% 52.0%* 52.1% 49.2% 51.1% 51.0% 51.5% Common Equity Ratio 51.5%
Pension Assets-12/17 $14274 mill. 19160 20330 21952 21794 21933 22735 24207 25058 29033 30149 32150 32900 Total Capital ($mill) 36200 Oblig $15536 mill. 20874 22464 23863 25093 26939 28436 29827 32209 35216 37600 40150 42075 Net Plant ($mill) 47800 Pfd Stock None 6.0% 5.3% 5.4% 5.5% 5.5% Return on Total Cap'I 5.5%
6.2% 5.7% 5.9% 6.2% 6.5% 6.4% 5.6%
Common Stock 310,730,465 shs. 9.4% 8.3% 8.8% 9.1% 9.6% 9.4% 8.5% 9.1% 8.3% 8.2% 8.0% 8.5% Return on Shr. Equity 8.5%
as of 4/30/18 9.5% 8.4% 8.9% 9.2% 9.6% 9.4% 8.5% 9.1% 8.3% 8.2% 8.0% 8.5% Return on Com Equity E 8.5%
MARKET CAP: $24 billion (Large Cap) 3.1% 2.5% 3.2% 3.1% 3.6% 3.6% 2.6% 3.5% 3.0% 3.0% 2.5% 2.5% Retained to Com Eq 2.5%
ELECTRIC OPERATING STATISTICS 67% 71% 65% 66% 62% 62% 69% 61% 64% 63% 67% 67% All Div'ds to Net Prof 68%
2015 2016 2017 BUSINESS: Consolidated Edison, Inc. is a holding company for opportunities through three wholly owned subsidiaries. ~ntered into
%Cha}e Retail Sales (KWH) +1.9 -.4 -2.8 Avg. In u~. Use (MWH~ NA NA NA Consolidated Edison Company of New York, Inc. (CECONY), which midstream gas joint venture 6/16. Purchases most of its power.
Avg.lndu~.Revsi (¢) NA NA NA sells electricity, gas, and steam in most of New York City and Fuel costs: 22% of revenues. '17 reported depreciation rates: 2.9%-
CapacityalPeak ~ NMF NA NA Westchester County. Also owns Orange and Rockland Utilities 3.1 %. Has 15,000 employees. Chairman, President & CEO: John Peakload,Summerl ) 13721 NA NA McAvoy. Inc.: New York. Address: 4 Irving Place, New York, New Annual load Factor(%/ NMF NMF NMF (O&R), which operates in New York and New Jersey. Has 3.7 mil-
%Change Customers yr-l!n~ NA NA NA lion electric, 1.2 million gas customers. Pursues competitive energy York 10003. Tel.: 212-460-4600. Internet: www.conedison.com.
F~ed Cha1ge Cov. (%) 370 352 354 We estimate that Consolidated A natural gas pipeline project is un-Edison's earnings will rise 3%-4% this der way, and another is being pro-ANNUAL RATES Past Past Est'd '15-'17 posed. ConEd's 12.5% stake in the pipe-of change (per sh) 10Yrs. 5Yrs. to '21-'23 year and next. ConEd's largest subsidi-Revenues -1.5% -1.5% 1.0% ary, Consolidated Edison Company of New line represents an investment of $400 mil-
"Cash Flow 4.0% 4.0% 4.5% York, is benefiting from rate relief. At the lion for the company. This is scheduled for Earnings 2.5% 2.0% 3.0% completion by yearend. ConEd also has a Dividends 1.5% 2.0% 3.5% start of 2018, electric and gas tariffs were Book Value 4.0% 3.5% 3.5% boosted by $155.3 million (2.0%) and $92.3 6.375% stake in a much-shorter pipeline million (5.6%), respectively. Increases of proposal.
Cal- QUARTERLY REVENUES ($ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year $155.2 million (1.9%) for electricity and The company has some financing
$89.4 million (5.1 %) for gas will take effect needs. The utilities plan to issue $1.3 2015 3616 2788 3443 2707 12554 billion-$1.8 billion of long-term debt this 2016 3157 2794 3417 2707 12075 at the beginning of 2019. Orange and 2017 3228 2633 3211 2961 12033 Rockland Utilities might also obtain a rate year. ConEd will issue up to $450 million 2018 3364 2750 3436 2750 12300 increase next year (see below). Customer of common equity, over and above what 2019 3450 2850 3500 2850 12650 growth is another plus. And oil-heating will be raised through the dividend rein-EARNINGS PER SHARE A users continue to convert to the use of gas vestment and other stock plans (perhaps Cal- Full $80 million).
endar Mar.31 Jun.30 Sep.30 Dec.31 Year heat. Our 2018 earnings estimate, which we raised by a nickel a share, is at the *conEd's renewable-energy subsidiary 2015 1.26 .74 1.45 .60 4.05 2016 1.05 .77 1.47 .64 3.94 midpoint of the company's targeted range continues to add projects. A 25-2017 1.27 .57 1.48 .78 4.10 of $4.15-$4.35 a share. We lifted our 2019 megawatt wind facility went into effect in 2018 1.37 .63 1.60 .65 4.25 estimate by $0.10 a share, to $4.40. the first quarter. The company has 1,561 2019 1.40 .65 1.65 .70 4.40 Orange and Rockland has a rate case mw of wind and solar projects in service or QUARTERLY DIVIDENDS PAID e
- pending. The utility is asking the New under construction.
Cal- Full endar Mar.31 Jun.30 Seo.30 Dec.31 Year York State Public Service Commission for High-quality ConEd stock has a divi-electric and gas increases of $22.5 million dend yield that is a bit above average 2014 .63 .63 .63 .63 2.52 for a utility. However, with the recent 2015 .65 .65 .65 .65 2.60 and $2.7 million, respectively, based on a 2016 .67 .67 .67 .67 2.68 return of ,9.75% on a common-equity ratio price well within our 2021-2023 Target 2017 .69 .69 .69 .69 2.76 of 48%. New rates should take effect at the Price Range, total return potential is low.
- 2018 .715 start of 2019. Paul E. Debbas, CFA May 18, 2018 (A) Diluted EPS. Exel. nonrec. gains (losses): Next earnings report due early Aug. (B) Div'ds base: net orig. cost. Rate allowed on com. eq. Company's Financial Strength A+
'02, \11¢); '03, (45¢); '13, (32¢); '14, 9¢; '16, historically paid in mid-Mar., June, Sept., and for CECONY in '17: 9.0%; O&R in '15: 9.0%; Stock's Price Stability 95 15¢; 17, 84¢; gain on discontinued operations: Dec.
- Div'd reinvestment plan avail. (C) Incl. earned on avg. com. eq., '17: 8.6%. Regulatory Price Growth Persistence 40
'08, $1.01. '16 EPS don't sum due to rounding. intang. In '17: $16.04/sh. (D) In mill. (E) Rate Climate: Below Average. Earnings Predictability 95**
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wfthout warranties of an~ kind. -
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. o part, I I I' , :1111!'111*1 ;
of I may be reproduced, resold, stored or transmftted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
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- 0.54 x Dividends p sh 1-fnr- 1
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Ann'I Tota1L2~T~~r!!::!:T'!...J-II_I_~ 111 Price Gain Return '
High 110 (+40%) 13% **,I ""' 11 * * .. ,L~**r*...-:, "' " ***-- 60 50 Low 85 (+10%) 7% ~ =***
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. 2Q2017 3Q2017 4Ql017 Percent 15 528 509 Hld's{000) 435858 442941 402762 531 494 531 shares 467 traded 101111111 5
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68.8 l-:2=0,:,02,..,...,2=0=0=3.,..2=0=0'""4..,..,.,20=0=5-+=20=0=s,...,..,,2=00=7 2008 2009 2010 2011 2012 2013 2014 2015 2016 2i!!o~11~2~0~1=a+-2=0~1~9..j....,©;,.,V=AL~U=EL~IN=E=Pu=s.~LL-c-,J...1.-23.........I 25.32 30.24 31.15 29.18 32.22 32.63 27.88 34.84 33.84 34.10 32.49 33.66 33.45 34.20 Revenues per sh 36.50 7.86 8.11 7.34 7.58 8.49 8.68 6.80 8.56 9.11 9.40 9.20 10.01 11.15 11.70 "Cash Flow" per sh 13.25 2.76 3.60 3.03 3.39 4.02 4.14 3.71 3.98 4.13 4.10 3.71 4.22 4.80 5.00 Earnings per sh A 5.50
' m m ~ m ~ ~ u ~ ~ ~ ~ ~ Div'd Decl'd per sh e
- 4.40 8.07 7.43 10.35 9.85 10.84 9.80 7.81 7.83 7.62 9.83 11.29 11.50 15.05 15.00 Cap'l Spending per sh 11.75 62.30 50.40 49.51 49.85 50.84 51.14 58.04 58.54 57.81 57.74 58.62 59.63 61.05 62.35 Book Value per sh c 66.00
- . 418.96 420.62 423.96 436.29 442.96 445.29 704.00 706.00 707.00 688.00 700.00 700.00 727.00 731.50 Common Shs Outst'g u 745.00 16.1 17.3 13.3 12.7 13.8 17.5 17.4 17.9 18.2 21.3 19.9 Botdfig res are Avg Ann'I PIE Ratio 18.0
.85 1.04 ;89 .81 .87 1.11 .98 .94 .92 1.12 .99 ValueLJne Relative PIE Ratio 1.00 estlnlates 4.4% 5.2% 6.2% 5.7% 5.2% 4.7% 4.4% 4.3% 4.3% 4.3% 4.2% Avg Ann'I Div'd Yield 4.5%
CAPITAL STRUCTURE as of 12/31117 13207 12731 . 14272 14529 19624 24598 23925 23459 22743 23565 24300 25000 Revenues ($mill) 27200 Total Debt $54442 mill. Due in 5 Yrs $19439 mill. 1279.0 1461.0 1765.0 1839.0 2136.0 2813.0 2934.0 2854.0 2560.0 2963.0 3435 3640 Net Profit ($mill) 4100 LT Debt $49035 mill. LT Interest $1790 mill. 32.5% 34.4% 32.6% 31.3% 30.2% 32.6% 30.6% 32.2% 31.0% 30.4% 15.5% 15.5% Income Tax Rate 15.5%
Incl. $1000 mill. capitalized leases.
(LT interest earned: 3.1 x) 16.0% 17.5% 22.7% 23.2% 22.3% 8.8% 7.2% 9.2% 11.7% 12.3% 11.0% 11.0% AFUDC %to Net Profit 10.0%
38.7% 42.6% 44.3% 45.1% 47.0% 48.0% 47.7% 48.6% 52.6% 54.0% 54.0% 55.0% Long-Tenn Debt Ratio 56.5%
Leases, Uncapitalized Annual rentals $218 mill. 61.3% 57.4% 55.7% 54.9% 52.9% 52.0% 52.3% 51.4% 47.4% 46.0% 46.0% 45.0% Common Equity Ratio 43.5%
Pension Assets-12/17 $9003 mill. 34238 37863 40457 41451 77307 79482 78088 77222 86609 90774 97000 101475 Total Capital ($mill) 112500 Oblig $8448 mill. 34036 37950 40344 42661 68558 69490 70046 75709 82520 86391 92675 98725 Net Plant ($mill) 108700 Pfd Stock None 4.8% 4.9% 5.5% 5.6% 3.6% 4.6% 4.8% 4.8% 4.0% 4.3% 4.5% 4.5% Return on Total Cap'I 5.0%
Common Stock 700,092,667 shs. 6.1% 6.7% 7.8% 8.1% 5.2% 6.8% 7.2% 7.2% 6.2% 7.1% 7.5% 8.0% Return on Shr. Equity 8.5%
as of 1/31118 6.1% 6.7% 7.8% 8.1% 5.2% 6.8% 7.2% 7.2% 6.2% 7.1% 7.5% 8.0% Return on Com Equity E 8.5%
MARKET CAP: $55 billion (Large Cap) .6% 1.1% 2.1% 2.2% .9% 1.5% 1.7% 1.5% .6% 1.2% 2.0% 2.0% Retained to Com Eq 1.5%
ELECTRIC OPERATING STATISTICS 89% 84% 73% 72% 82% 78% 76% 79% 91% 83% 76% 76% All Div'ds to Net Prof 80%
%Change Relail Sales (Kl',ll) 2015 2016
+.6 -.3
~ii 1-B-U-SI-N~ES_S_:_D_uk~e-E-n-er-gy.....
Co-r-po-ra~ti-on-is-a~h-01-di-ng-c~o-m-pa_n_y~fu-r-ut-il-......_r_e_sid-e-nt~ia-1,-4-1-%~;-ro_m_m_e~rc-ia-l,-2-9~%-;-in-d-us-tr-ia-l,-1-4'-Yo;-o-t-he~r.-1-6-%-.~
Avg. lnlfusl. Use (MWH) 2883 2908 2914 ities with 7.4 mill. elec. customers in NC, FL, IN, SC, Oh, & KY, and Generating sources: roal, 27%; nuclear, 27%; gas, 23%; other, 1%;
Avg. lndusl. Revs._p.er )(\'Ill (¢) NA NA NA 1.5 mill. gas customers in OH, KY, NC, SC. and TN. Owns inde- purchased, 22%. Fuel rosts: 30% of revs. '17 reported deprec. rate:
Capacity at Peak (Mill NA NA NA pendent power plants & has 25% stake in National Methanol in 2.8%. Has 29,100 employees. Chairman, President & CEO: Lynn J.
Peak load, Summer (Mw) NA NA Annual load Factor(%) NA NA ~~ Saudi Arabia. Acq'd Progress Energy 7/12; Piedmont Natural Gas Good. Inc.: DE. Address: 550 South Tryon St., Charlotte, NC
%Change Cuslomers (avg.) +1.2 +1.4 +1.3 10116; discontinued most int'I ops. in '16. Elec. rev. breakdown: 28202-1803. Tel.: 704-382-3853. Internet: www.duke-,,nergy.com.
t-:---,--=-----,------------------------------......C;....---1 F~edChargeCov.(%) 317 264 272 Duke Energy has received rate in- on June 1st.
..A_N_N_U_A~L-RA~TE~S--Pa_s_t--P-as_t_E-st-,d-,- -_,-'"' creases in two states. The settlement for Earnings are likely to advance signifi-15 17 ofchange(persh) 10Yrs. svrs.
- to'21-'23 its Progress Energy unit was approved by cantly in 2018 and 1nore 1nodestly in Revenues 2.0% 1.5% 1.5% the North Carolina regulators. Rates were 2019. The third-quarter comparison "Cash Flow" 2.0% 3.5% 5.5% raised by $193 million, based on a return should be easy, as profits in that period of Bfvrci~R~s 1 ~:5~ 2 :~~ ~:g~ of 9.9% on a common-equity ratio of 52%. 2011 were hurt by mnd weather patterns Book Value .5% 2.0% 2.0% However, certain costs were disallowed, and some unusual (but not nonrecurring) 1-C-al----r--Q-U-AR_TE_R-~-Y-REV-EN-U-ES-($_m_i_ll.)~,--F-ul-il including some associated with coal ash costs. Our 2018 estimate of $4.80 a share endar Mar.31 Jun.30 Sep.30 Dec.31 Year basin remediation. (Ongoing coal ash costs is near the upper end of Duke's guidance r-=,20""'15=-t-:6""06:-:5,---::55::-::8""9-6="'4"' 83c---::53.,,.,2,,. 23,.,4.,,,
2-+-=- 59,-t will be deferred, to be considered for re- of $4.55-$4.85 a share. Besides the easy 2016 5377 5213 6576 5577 22743 covery in the utility's next rate case.) This comparison, rate relief should benefit the 2017 5729 5555 6482 5799 23565 forced Duke to take a pretax charge of bottom line this year and next. We figure 2018 6135 5650 6665 5850 24300 $100 million (included in our earnings profits will advance 4%, to $5.00 a share, 2019 6300 5750 6950 6000 25000 presentation) in the first quarter. Sepa- in 2019.
1-C-al-"-+---EA-R_N_IN-GS_P_E_R_SHA-RE-A---11--F-ul-il rately, the utility was granted a tariff in- Duke executed a forward sale of co1n-endar Mar.31 Jun.30 Sep.30 Dec.31 Year crease of $8.4 million in Kentucky, based 1non stock. The closing, by yearend, will 1---1-........-1.---.-8--1~.4-- - .- -+---.----<
20 5 09 7 4 70 4 10 on a return of 9.725% on a common-equity raise more than $1.5 billion and will in-2016 .83 .90 1.44 .54 3.71 ratio of 49%. crease the share count by more than 21 2017 1.02 .98 1.36 .86 4.22 Other regulatory 1natters are pending. million. The proceeds will be used for gen-2018 1.17 1.03 1.55 1.05 4.80 Duke Energy Carolinas is seeking a hike eral corporate purposes.
2019 1.20 1.10 1.60 1.10 5.00 of $647 million, based on a return of This stock offers an attractive divi-1-C-al---+--,,Q,-,UA,.,,R,..TE--R""'LV""D--IV"'ID""EN--D--S-:::-PA:-:,ID:-B-.--11--F-ul--il 10.75% on a common-equity ratio of 53%. dend yield. The yield is more than one endar Mar.31 Jun.30 *Seo.30' Dec.31 Year New tariffs should take effect soon. In percentage point above the utility mean.
t-,~~-1-:-+--:-j~-5--J-~-s-~:~-~~--:~-~~-+--~-:J--i~ ~$1~9~~d lrlo~~~ b:i:~tdc~~ddi:tr~e~~!~~f egta8~4et:i !~o~d*ec!~re~ctlt~~le3_ itJh~;:i:r p~;br:~ho:i~
2016 .825 .825 .855 .855 3.36 mi ion, ase on a return o . 10 on pro uce tota returns t at are a ove aver-2017 .855 .855 .89 .89 3.49 a common-equity ratio of 50. 75%. The com- age for a utility, as well.
2018 .89 pany is asking for new rates to take effect Paul E. Debbas, CFA May 18, 2018 (A) Dil. EPS. Exel. nonrec. losses: *12*, 70¢; egs. due early Aug. (B) Div'ds paid mid-Mar., Rates all'd on rom. eq. in '13 in NC: 10.2%; in Company's Financial Strength A
'13, 24¢; '14, 67¢; '17, 15¢; '18, 11¢; gain June, Sept., & Dec.* Div'd reinv. plan avail. '17 in SC: 10.1%; in '09 in OH: 10.63%; in '04 Stock's Price Stability 100 (losses) on disc. oes.: '14, (80¢); '15, 5¢; '16, (C) Incl. intang. In '17: $45.48/sh. (D) In mill., in IN: 10.3%; earn. avg. com. eq., '17: 7.1%. Price Growth Persistence (60¢). '16 EPS don t sum due to rounding. Next adj. for rev. split. (E) Rate base: Net orig. cost. Reg. Clim.: NC Avg.; SC, OH, IN Above Avg.
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wtthout warranties of any kind.
TH.E PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part; I 1111..'{~j I * ,
of I may be reproduced, resold, stored 01 transmitted in any printed, electronic or other form, or used !or generating or marketing any printed or electronic publication, service or product:
rmEarnings Predictability
- lili'"111 40 85-
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TIMELINESS 3 Lowered 121 3 18 High: 60.3 55.7 36.7 39.4 41.6 48.0 54.2 68.7 69.6 78.7 83.4 67.6 * . Target-Price Range
>---'L=o~w~:~~42=*-8~=26~-~7~23.1 30.4 32.6 39.6 44.3 44.7 55.2 58.0 62.7 57.6 2021 2022 2023 SAFETY 2 Raised 513/13 LEGENDS TECHNICAL 4 Raised 4/20/18 -. . . . 1.00 x Dividends p sh
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- 1 High 100 (+55%l 14% t..,._.,._.,.,,.,1;,..:=~=-6,...,:r;ffili,,11.!-:1-:-ril1,".'.F'.!!!Jlfl!.'.-F-...L-:.+--+--+--l--+-'--l--+--+--+--l--+--l-32 111 Low 75 (+15% 8% .-- ' 24 Insider Decisions * * .... * ...... *** -* **** ** ***-. ** ..... **** * "*, ........ -. 20 J JASON DJ F 16 to Buy O O O O O O O O O Options 2 O 1 O O 1 011 O to Sell 2 0 1 0 0 1 0 0 0 Institutional Decisions toBuy to Sell 2Q2017 299 236 3Q2017 274 258 4Q2017 Percent 278 shares 225 traded 10 5
iii 15 * . .
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12 Hld's(ODD) 290101 28837 4 267652 111 5 yr. 44.9 68.8
'"'2='=0,;;;o;,;,;2~20='=0='=3..,=:-20:;;;o,;..,4,.,=;;2;,;.00;;;5;.+-,,2=0=0s="'""'2=0=07='J/ol2~00a 2009 2010 2011 2012 2013 2014 2015 2016 201~1~20~1=a-l-,,,20""1'""9,-1--.,;,.©v-A-LU=E-uN=E=pu=0~.L~LC~1,,h1,..,*2""3""""
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 35.37 36.43 37.81 38.35 40.20 Revenues per sh 46.75 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 10.35 10.43 11.03 11.45 12.05 "Cash Flow" per sh 14.25 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 4.15 3.94 4.51 4.55 4.70 Earnings per sh A 5.50
.. .. .80 1.02 1.10 1.18 1.23 1.25 1.27 1.29 1.31 1.37 1.48 1.73 1.98 2.23 2.45 2.57 Div'd Decl'd per sh 8
- 3.10 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 12.97 11.46 11.75 13.30 15.05 Cap'l Spending per sh 15.75 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 34.89 36.82 35.82 37.35 38.90 Book Value per sh c 44.50 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 Common Shs Outst'g u 325.81 7.8 7.0 37.6 11.7 13.0 16.0 12.4 9.7 10.3 11.8 9.7 12.7 13.0 14.8 17.9 17.2 Boldfigresare AvgAnn'IP/ERatio 15.5
.43 .40 1.99 .62 .70 .85 .75 .65 .66 .74 .62 .71 .68 .75 .94 .85 Value Une Relative P/E Ratio .85
.. ** 3.1% 2.6% 2.6% 2.2% 2.7% 4.0% 3.7% 3.4% 3.0% 2.8% 2.6% 2.8% 2.8% 2.9% estlnlates Avg Ann'I Div'd Yield 3.6%
CAPITAL STRUCTURE as of 12/31/17 14112 12374 12409 12760 11862 12581 13413 11524 11869 12320 12500 13100 Revenues ($mill) 15200 Total Debt $14516 mill. Due in 5 Yrs $4793 mill. 1266.0 1115.0 1153.0 1112.0 1594.0 1344.0 1539.0 1480.0 1422.0 1603.0 1620 1670 Net Profit ($mill) 1970 LT Debt $11642 mill. LT Interest $569 mill. 30.7% 33.0% 32.1% 25.7% 14.3% 25.2% 22.4% 6.6% 11.1% 5.0% 10.0% 10.0% Income Tax Rate 10.0%
(LT interest earned: 4.0x)
Leases, Uncapitalized Annual rentals $335 mill. 8.9% 10.5% 16.9% 14.8% 8.5% 7.8% 5.8% 8.0% 6.8% 7.2% 8.0% 7.0% AFUDC %to Net Profit 7.0%
Pens. Assets-12/17 $3616 mill. Oblig $4179 mill. 51.2% 49.3% 51.8% 55.3% 45.2% 45.7% 44.1% 45.0% 41.8% 45.6% 48.0% 48.0% Long-Term Debt Ratio 47.5%
Pfd Stock $2193 mill. Pfd Div'd $124 mill. 44.5% 46.5% 44.3% 40.6% 46.2% 46.2% 47.2% 46.7% 49.2% 45.8% 44.0% 44.5% Common Equity Ratio 45.5%
4,800, 198 sh. 4.08%-4. 78%, $25 par, call. $25.50- 21374 21185 23861 24773 20422 21516 23216 24352 24362 25506 27500 28525 Total Capital ($mill) 31800
$28.75/sh.; 3,250,000 sh. variable, noncum., call. 18969 21966 24778 32116 30273 30455 32981 35085 37000 39050 41125 43675 Net Plant ($mill) 50700
$100; 1,250,000 sh. 6.5%, cum., $100 liq. value; 350,000 sh. 6.25%, $1000 liq. value; 460,012 sh. 7.4% 6.9% 6.3% 6.0% 8.9% 7.3% 7.7% 7.1% 6.9% 7.3% 7.0% 7.0% Return on Total Cap'I 7.5%
5.1 %-5. 75%, $2500 liq. value. 12.1% 10.4% 10.0% 10.0% 14.2% 11.5% 11.9% 11.1% 10.0% 11.6% 11.5% 11.0% Return on Shr. Equity 12.0%
Common Stock 325,811,206 shs. as of 2/20/18 12.8% 10.8% 10.4% 10.5% 15.9% 12.5% 13.0% 12.0% 10.8% 12.7% 12.5% 12.0% Return on Com Equity E 12.5%
MARKET CAP: $21 billion (Large Cap) 8.6% 6.7% 6.5% 6.3% 11.4% 8.1% 8.8% 7.2% 5.6% 6.6% 5.5% 5.5% Retained to Com Eq 6.0%
ELECTRIC OPERATING STATISTICS 35% 41% 40% 43% 32% 40% 37% 44% 53% 52% 57% 58% All Div'ds to Net Prof 58%
%Change Retail Sales (KWH) 2015 2016 2
-1.4 -2.6
°;~ 1--B-U-SI-N~ES_S_:_E_d~is-on-ln-te~rn-at-io-na-l~(f-orm-e-rly~S-C_E_C_o~~-)-is_a_h~o-ld-in_g-1.d_e-nt-ia-l,~3-7o/c-,;-c-om.,__m_er-ci-al~,4-4_%_;-ind~u-st-ria-l,-6-o/c-,;-m-h-er-,1-3_%__~G-en-e-ra--~
Avg. lmfu~. Use (MWH) 703 664 NA company for Southern California Edison Company (SCE), which ting sources: gas, 6%; nuclear, 6%; hydro, 5%; purchased, 83%.
Avg. lndu~. Revs1.e1 l(1Mj (II 9.07 6.51 NA supplies electricity to 5.1 mill. customers in a 50,000-sq.-mi. area in Fuel costs: 38% of revs. '17 reported depr. rate: 3.8%. Has 12,500 Capaci~ at Peak (MW) NA NA ~~ central, coastal, & southern CA (excl. Los Angeles & San Diego). empls. Chairman: William P. Sullivan. Pres. & CEO: Pedro J. Piz-Peak load, Summer !Mw) 23079 23091 235NA Edison Energy is an energy svcs. co. Disc. Edison Mission Energy zaro. Inc.: CA. Address: 2244 Walnut Grove Ave., P.O. Box 976, Annual LoadFacior(Y,) 52.2 50.7
%ChangeCuslomers(yr-end) +.6 +.5 +.7 (independent power producer) in '12. Elec. rev. breakdown: resi- Rosemead, CA 91770. Tel.: 626-302-2222. Web: www.edison.com.
f~edChargeCov.(%) 247 246 241 Investors remain concerned about the the beginning of 2018.) The utility's three-1-A-N_N_U..:A_L_RA..:.T..:.E_S_P-as-t--P-as-t-Es_t_'d-,1-5-_,1--17 possible wildfire liability of Edison In- year capital spending plan calls for $1.4 ofchange(persh) 10Yrs. 5Yrs. to'21-'23 ternational's utility subsidiary. billion for grid modernization, which is Revenues -.5% -.5% 4.0% Southern California Edison's service area somewhat controversial because the Cali-
"Cash Flow" 4.0% 3.5% 5.0% had wildfires in the fall of 2017. The cause fornia commission has not been asked to Earnings 2.5% 2.5% 4.5%
Dividends 6.0% 9.0% 8.0% of the wildfires has not yet been deter- approve such spending in previous rate Book Value 4.5% 3.0% 3.5% mined, but SCE has already been hit with cases. An order is expected by yearend.
1--C-al----Q-UA-R-TE-R-LV_R_EV_E-NU_E_S_($_m_ill.-)~-F-ul....,I some lawsuits alleging that its power lines Tax reform is slightly negative for the endar Mar.31 Jun.30 Sep.30 Dec.31 Year were at fault. (It has $1 billion in liability company. Edison International has about
,__20-1--+-2-5 -- - - ~ - - -- - - - - ...., insurance.) Under California's inverse con- $1.75 billion of long-term debt at the 5 2 2908 3763 234 1 11524 2016 2440 2777 3767 2885 11869 demnation law, a utility can be held liable parent level, so corporate interest and 2017 2463 2965 3672 3220 12320 if its power lines contributed to the wild- other expenses will have a lower tax 2018 2500 3000 3800 3200 12500 fires, even if the utility followed accepted shield. This is also true for the company's 2019 2600 3150 4000 3350 13100 inspection and safety rules. If this occurs, nonutility energy-services subsidiary,
,_c_a_l_-+---EA-R_N_IN_G_SP_E_R_SH_A_R_EA___F_u_ll there is no assurance that the utility will Edison Energy, which is still in its start-endar Mar.31 Jun.30 Sep.30 Dec.31 Year be allowed to pass these costs through to up phase and is in the red. Management
....,..,.,cc-+--,.,.,- -,.._cc- -,,__,..- - .,..-+~..,.-i 1 15 ratepayers. So, the company is pursuing a estimates that the corporate and non-20 15 91 1 15 94 4 15 2016 .85 .86 1.27 .96 3.94 three-pronged strategy to address this utility. drag on earnings will amount to 2017 1.11 .85 1.43 1.12 4.51 risk, seeking legislative, regulatory, and $0.25-$0.30 a share this year. Note that 2018 1.10 .90 1.45 1.10 4.55 judicial solutions to this problem. the company is not providing earnings 2019 1.15 .90 1.50 1.15 4.70 SCE is awaiting an order on its gener- guidance as long as the general rate case 1--C-al---+--Q-UA_R_T-ER-LV_D_IV-ID-E-ND_S_P_I\I_D_B_*-+--F-u--ill al rate case. The utility has revised its is pending.
endar Mar.31 Jun.30 Seo.30 Dec.31 Year request to pass through to customers the The wildfire risks hurt the stock last 1---1--+'"".'"'"-'--""".="-'--=--'."'.:.:.=....c::.:.c::.:.:-=+--- --1 benefits of federal tax reform. SCE is ask- year, and the price has risen just 20 4 355 35 5 35 5 355 1 42 2015 .4175 .4175 .4 175 .4 175 1:67 ingdf~r a reductiofn$o f $ 106 m illion 1d*n $2 0 18 s 1ightly in 2018. The dividend yield and 2016 .48 .48 .48 .48 1.92 an mcreases o 4 3 1 mi11ion an 50 3 3 - to 5 -year tota1 return potentia1 are 2017 .5425 .5425 .5425 .5425 2.17 million at the start of 2019 and 2020, res- above average for this industry.
2018 .605 .605 pectively. (The order will be retroactive to Paul E. Debbas, CFA
- April 27, 2018 (A) Dil. EPS. Exel. nonrec. gains (losses): '02, lions: '12, ($5.11); '13, 11¢; '14, 57¢; '15, 11¢. charges. In '17: $15.08/sh. (D) In millions. (E) 1 *company's Financial Strength A.
$1.48; '03, (12¢); '04, $2.12; '09, (64¢); '10, Next earnings report due late July. (B) Div'ds Rate base: net orig. cost. Rate allowed on com. Stock's Price Stability 90 54¢; '11, ($3.33); '13, ($1.12); '15, ($1.18); '17, paid late Jan., Apr., July, & Oct.
- Div'd rein- eq. in '15: 10.45%; earned on avg. com. eq., Price Growth Persistence 50
($1.37); gains (loss) from discontinued opera- vestment plan available. (C) Incl. deferred '17: 12.2%. Regulatory Climate: Average. Earnings Predictability 60 *
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wtthout warranties of any kind.,
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscribers own, non-commercial, inlemal use. No part. ~scribe call 1-800-VALUEL~~J of tt may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or eleclronic publication, service or product.'
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/( ~ ~1101.------1 TIMELINESS 3 Lowered1/26/18 Higli: 28.2 25.5 21.1 28.7 35.7 35.3 39.1 42.2 41.3 48.8 61.2 55.8 * *Target-Price Range SAFETY 2 Raised 5111107 f-=~"'~~""~'-N"-o""'s2"'0"'.8"-'---1-"'5'"".2"-'--....;11.6 18.7 26.7 29.2 31.8 33.4 33.B 37.2 44.7 48.1 2021 2022 2023 TECHNICAL 3 Lowered 4/6/18 -
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.tu,n-23 t'KUJl:l,;IIUN:i o~~~~!/:ka indicates recession t-+---t--+--=-t--+---t---::=_9~'---::,:..-a~l.';':-::'"-,..*-o--+
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l---+----l--+ 40 50 Price Gain AnR~tJ~al ,---+----,1----+----,1---~,..--+-",,1..,11,l'+-~'*..,.~*"-".,._1"_1_,*1_,1_1-_"_ .. ,1,,-+-1_1_111_,*-+---1----+---1----1---1----1----,1-30 High 60 (+20%1 8% ,111 , .... I" II *I, .. .,,, I I / / 25 Low 45 (-10% 1% -.. 20 Insider Decisions .,,, ******-**** * * * "Ill ii.* ,1 ,* *,.:***** 15 J J A S O N D J F *' 11'1!--*" ******" ' ***-,, *,"""' *-***,,*'* "**, ,*"
- toBuy O O O O O O O O O 10 Options 340040047 to Soll 1 o o o o o o o o l---t---t---t---l----t---1----t---l----+---l----+ ---l----+----l % TOT. RETURN 3/lB 1-7.5 Institutional Decisions I THIS VLARJTll' 2Q2017 3Q2017 4Q2017 Percent 21 yr. sr~~K IN~~ '"'
toBuy 117 96 86 shares 1 14 .,...,,-+--t;-t-H-tttt1"thh-*1tt:-'"-t-.---t----.-t----tt--,----,t--.rlT ,---t---t yr. 1 toSell 78 83 67 traded 7 11.,1 .,II 1* I ,lllmlllllmt I I ., ., htJllU 3 43 _5 24_3 1 Hld's(0001 45099 45123 39640 lllf11111111illllllllllllllJJJ,IJl!UU,lft111111lfllfllllt1111fff11 1111111111 111lll111111111ff-l 5yr. 75.1 68.8 1-,2""0~0"'"2,..2"'0'"'0;...3..,...,,.20""0'""4~2"""00'"'5--2"""00=5~2"""00=7-2/.!J.OOB 2009 2010 2011 2012 2013 2014 2015 2016 2017 2:..0'"'1.,..8+,,,20""'1""9-"'=,V.""1'. ,.,.LU"'"E'""LIN""E""'PU""B,.,L.,.,LC"",..,.1""-2""3 . -t 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 21.01 21.89 22.59 22.80 23.35 Revenues per sh 25.00 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 5.75 5.98 6.17 6.35 6. 60 "Cash Flow" per sh 7.50
.57 .64 .69 .76 1.27 1.63 1.73 1.50 2.07 2.48 2.26 2.20 2.27 2.03 2.39 2.42 2.45 2.60 Earnings per sh A 3.00
.. .. .. .. .. .. .. .66 .97 1.05 1.11 1.17 1.23 1.32 1.42 1.52 Div'd Decl'd per sh B 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 8.55 7.03 5.91 6.80 6.85 Cap'I Spending per sh 7.25 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 25.13 26.52 28.14 29.20 30.25 Book Value per sh c 33.50 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 40.44 40.52 40.58 40.60 40.70 Common Shs Outst'g u 41.00 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 18.3 18.7 21.8 Bold fig res are Avg Ann'I P/E Ratto 17.0 1.26 1.04 1.16 1.42 .91 .81 .72 .72 .68 .79 .92 .89 .86 .92 .98 1.10 Value Una Relative P/E Ratio .95
.. .. .. .. .. .. . . 2.1% 3.0% 3.0% 3.0% 3.1% 2.7% 2.5% estin ates Avg Ann'I Div'd Yield 3.5%
CAPITAL SlRUCTURE as of 12/31/17 1038.9 828.0 877.3 918.0 852.9 890.4 917.5 849.9 886.9 916.8 925 950 Revenues ($mill) 1025 Total Debt $1369.5 mill. Due in 5 Yrs $218.5 mill. 77.6 66.9 90.3 103.5 90.8 88.6 91.4 81.9 96.8 98.3 100 105 Net Profit ($mill) 125 LT Debt $1196.0 mill. LTlnterest $72.3 mill.
(LT interest earned: 2.9x) 32.8% 33.1% 36.1% 34.2% 34.1% 33.0% 31.0% 29.9% 35.8% 34.2% 24.5% 24.5% Income Tax Rate 24.5%
20.4% 24.3% 22.1% 17.6% 22.4% 24.1% 30.8% 27.5% 17.6% 11.2% 13.0% 12.0% AFUDC %to Net Profit 14.0%
53.8% 52.7% 51.2% 51.8% 54.8% 51.4% 53.5% 52.7% 52.7% 51.2% 53.0% 52.0% Long-Tenn Debt Ratio 54.5%
Pension Assets-12/17 $304.4 mill. 46.2% 47.3% 48.8% 48.2% 45.2% 48.6% 46.5% 47.3% 47.3% 48.8% 47.0% 48.0% Common Equity Ratio 45.5%
Oblig $362.0 mill. 1503.9 1527.7 1660.1 1576.7 1824.5 1943.5 2118.4 2150.8 2269.9 2338.2 2530 2575 Total Capital ($mill) 3025 Pfd Stock None 1595.6 1756.0 1865.8 1947.1 2102.3 2257.5 2488.4 2695.5 2821.2 2928.4 3045 3160 Net Plant ($mill) 3550 Common Stock 40,661,003 shs. 6.7% 6.0% 7.0% 8.3% 6.5% 6.1% 5.7% 5.3% 5.8% 5.8% 5.5% 5.5% Return on Total Cap'I 6.0%
as of 1/31/18 11.2% 9.3% 11.1% 13.6% 11.0% 9.4% 9.3% 8.1% 9.0% 8.6% 8.5% 8.5% Return on 5hr. Equity 9.0%
11.2% 9.3% 11.1% 13.6% 11.0% 9.4% 9.3% 8.1% 9.0% 8.6% 8.5% 8.5% Return on Com Equity E 9.0%
MARKET CAP: $2.0 billion (Mid Cap) 11.2% 9.3% 11.1% 10.0% 6.3% 4.9% 4.8% 3.4% 4.4% 3.9% 3.5% 3.5% Retained to Com Eq 3.5%
ELECTRIC OPERATING STATISTICS .. .. .. 26% 43% 47% 49% 57% 51% 54% 57% 58% All Div'ds to Net Prof 61%
%Change Retail Sales (K1Mi) 2015 2016 2
+2.3 +.1
~! t---B-U-Sl~N~ES_S_:_E~I-P-a-so---cE~le-ct~ric.....,C-om_p_a_n_y_(E~P~E-)-p-ro-v-id-es~el-ec-tr-ic~a~b-le-.-G-e-ne_ra_t-ing~s-ou-~-e-s:-nu_c_le-ar-,-49-%-,;-g_a_s,-36-%-,;-p~~-~-ha-s-ed-,~
Avg. lndu&. Use (MWHI 21687 21036 21553 service to 417,000 customers in an area of approximately 10,000 15%. Fuel costs: 27% of revenues. '17 reported depreciation rate:
Avg. lndu&. RevsJ_er Kl'.li (¢) NA NA NA square miles in the Rio Grande valley in western Texas (68% of 2.3%. Has about 1,100 employees. Chairman: Charles A.
Capacity at Peak (Mw~ 2055 2080 ~8~~ revenues) and southern New Mexico (19% of revenues), including Yamarone. President & CEO: Mary E. Kipp. Incorporated: Texas.
Peak load, Summer ) 1794 1892 Annual load Factor ( ,) NA NA NA El Paso, Texas and Las Cruces, New Mexico. Wholesale is 13% of Address: Stanton Tower, 100 North Stanton, El Paso, TX 79901.
%Change Custome1S (yr-en~ +1.4 +1.6 +1.7 revenues. Electric revenue breakdown by customer class not avail- Tel.: 915-543-5711. Internet: www.epelectric.com.
F~edChargeCov.(%) 218 267 263 We estiinate that El Paso Electric more volatile.
t-A-N_N_u""'A'-L-RA-'-T'-ES--P-as-t--P-as_t_E-st-'d-,- -_,--l 15 17 Co1npany's earnings will advance The utility is required to file a general ofchange(persh) 10Yrs. 5Yrs. to'21-'23 slightly this year. The utility will have a rate case in New Mexico by July of Revenues 2.0% .. 2.5% full year's worth of the rate increase in 2019. EPE may file sooner; we note that "Cash Flow 5.5% 1.0% 4.0% Texas that took effect in July of 2017. EPE the portion of Units 3 and 4 of a new gas-5!7~i~R~s 65
- :~ 18 _oo/~ g~ is also benefiting from above-average cus- fired generating station that is allocated to Book Value
- 7.5% 6.5% 4.0% tamer growth that stems from the healthy New Mexico is not reflected in rates. How-i----.--------,=-,----.---t QUARTERLY REVENUES ($ mill.) economy in El Paso and environs. On the ever, the regulatory climate in New Mexi-Cal- Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year other hand, the weather was favorable for co is difficult (not just for EPE), so the 2015 163.8 219.5 289.7 176.9 849.9 the company in 2017, and we assume company might well wait until it is re-2016 157.8 217.9 323.2 188.0 886.9 normal weather this year. Our 2018 earn- quired to file before it puts forth its rate 2017 171.3 251.8 297.5 196.2 916.8 ings estimate, which we lowered by $0.20 application.
2018 170 255 305 195 925 a share, is within management's guidance We expect a dividend hike at the 2019 175 260 315 200 950 of $2.30-$2.65 a share. Next year, the utili- board 1neeting in May. This has been Cal- EARNINGS PER SHARE A Full ty will benefit from rate relief in Texas the pattern since the directors initiated a endar Mar.31 Jun.30 Sep.30 Dec.31 . Year through transmission and distribution reg- common dividend several years ago. We 2015 .09 .52 1.40 .02 2.03 ulatory mechanisms. However . . . estimate an increase of $0.10 a share 2016 d.14 .55 1.84 .14 2.39 Earnings have beco1ne less predic- (7.5%) in the annual disbursement. EPE's 2017 d.10 .89 1.47 .16 2.42 table. The company owns a 15.8% share of goal is a payout ratio in a range of 55%-
2018 d.15 .75 1.70 .15 2.45 the Palo Verde nuclear station in Arizona. 65%.
2019 d.10 .80 1.75 .15 2.60 Like any utility that owns nuclear assets, This stock has a dividend yield that is Cal- QUARTERLY DIVIDENDS PAID B Full EPE invests1 in a trust to provide funds for below the industry 1nean. Like many endar Mar.31 Jun.30 Sep.30 Dec.31 Year nuclear decommissioning. The gains or utility issues, the recent quotation is 2014 .265 .28 .28 .28 1.11 losses on the nuclear decommissioning within our 2021-2023 Target Price Range .
2015 .28 .295 .295 .295 1.17 trust are now being reflected in the income Accordingly, total return potential over 2016 .295 .31 .31 .31 1.23 statement, instead of through Accumu- that time frame is unspectacular, despite 2017 .31 .335 .335 .335 1.32 lated Other Comprehensive Income on the good dividend growth prospects .
2018 .335 balance sheet. This will make earnings Paul E. Debbas, CFA April 27, 2018 (A) Diluted earnings. Exel. nonrecurring gains dates in late March, June, Sept., and Dec. '16: 9.48%; earned on avg. com. eq., '17: Company's Financial Strength B++
(loss): '03, 81¢; '04, 4¢; '05, (2¢); '06, 13¢; '10, (CJ Incl. deferred charges. In '17: $96.0 mill., 8.9%. Regulatory Climate: TX, Average; NM, Stock's Price Stability 90 24¢. Next earnings report due early May. $2.37/sh. (D) In millions. (E) Rate allowed on Below Average. Price Growth Persistence 70 (B) Initial dividend declared 4/11; payment common equity in TX in '17: 9.65%; in NM in
© 2018 Value Line, Inc: All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wnhout warranties of any kind.,
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part .,,
of nmay be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or ma,keting any printed or electronic publication, service or product:
Earnings Predictability I I ' , 11a~:Oll,.11 'Ull:tllll11 I
75-*.
- ,
18-KCPE-480-RTS t--lD_A_C_Q_B_n r,lN_C~~-..---.--'-,-IREC-ENT_!8_8~_.__
1 NYSE-IDA PRICE , IP/E~11_1~(_Trail~ing:_21.1LR-ELA~TIVE_1_1!.__D1V~'D RATIO , Median: 14.0 P/ERATIO , YLD 1~1_0,0~.* /( ' .-=-*- -
TIMELINESS 2 Raisedl2/22/H High: 39.2 35.1 32.B 37.B 42.7 45.7
- 54.7 70.1 10:5 83.4 100.0 65.0 77.5 91.4 79.6
- Target Price Range 2021 2022 2023 Low: 30.1 21.9 20.9 30.0 33.9 38.2 43.1 50.2 55.4 SAFETY 2 Raised 8/2/13 *_L_EG~-~f;Dividends Psh t--+----!---+----!---+----:-+--+----4--+----4--+ ----4--+---+ 120 TECHNICAL 3 Lowered 2/23/18 . . . . ~~\~f~eb~r/g!e~~~n~~e t--+----!---f----!---f----4--+-- _--:-+,-,,,-,,-,i'lnl*-.,0 -+----4--+-.- . *-.-.+-.-**-.-.-+- ~~O BETA .70 (1.00 = Market) 1-- l!TI-=2!15R'OJ1:C'l"IIT!g--t_D...c~'!!!.~~~~:~~~yi~,~al!..:,"!!'ndl!E_ic~ates~re::!cess~io'!!_nt--+----!---+--=---l---f--,:a,lflt;F.,,......-:.,l"'L!l'~":.:."_'"+---*....:*.:i.=-*--..-,d,c--+----l--+~---+-64 I 2 .:u.:*r-23 l'l'IUJC~ I IUNl:i 1-==i::==t==::::i:=--l---l--~~l/~=t;;;i;Il';m*~~lil'._+'"__"': _:11:.:_' l_j___ j__ _j___j_"__*_ _j___ j__ _j___i,48 Ann'I Total Price Gain Return r"'~*l:;;'"="f"-'"u,*~
High Low 90 65 ~*11
(-2 o}.
3%
-4%
1-!=:~~:;......,....!~'.!!!l._:~~j,...-=-**-**:.:.***k--::::..+:'
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"~==-***;",f~r!!:- *-t--;;;:-t-----..;,l----:;:-:-t--+--l---;*"--..b,.-.-..-.f----t-- -+--t---+--t-2240 Insider Decisions "** ~- ....... l"!e*.
J J A S 0 N D J F l---+---l----+---1----l----1----l---+--+--+- -+--+--+--+--+--+---+-16
.** e e* L--
to Buy 0 0 0 0 0 0 0 0 0 Options 0 0 0 0 0 0 0 010 l---+--+---+--+---+--+---+--+---+--+---+ --+---+--+---+--+---+-12 to Sall 2 0 0 0 0 0 0 0 0 111;,,,., . ,: ,
% TOT. RETURN 3/18 ,-8 Institutional Decisions 1111 THIS VL ARITH."
to Buy 2Q2017 139 3Q2017 116 4Q2017 Percent 127 shares 15 10 I.
.11,11, 1111-,1~, .... , ..
I II 1 yr.
3 yr.
STOCK 9.2
- 52. 7 INDEX 9.7 ::
24.3 ._
tos,11 91 113 86 traded 5 5yr. 111.6 68.8 Hld'slOOO} 45985 45708 38200 111111111111111111 11 11111111111 11111 111111111111n11111111 11 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 © VALUE LINE PUB. LLC 1, 1-23 24.43 20.41 20.00 20.15 21.23 24.~1 25.51 25.23 25.04 26.76 26.60 27.00 Revenues per sh 28.75 4.08 3.50 4.12 3.87 4.58 6.29 6.58 6.70 6.86 7.50 7.65 8.05 "Cash Flow" per sh 9.25 1.63 .96 1.90 1.75 2.35 3.64 3.85 3.87 3.94 4.21 4.15 4.35 Earnings per sh A 4.75 1.86 1.70 1.20 1.20 1.20 1.57 1.76 1.92 2.08 2.24 2.40 2.56 Div'd Decl'd per sh 8
- t 3.05 3.53 3.89 4.73 4.53 5.16 4.68 5.45 5.84 5.89 5.66 6.25 6.40 Cap'I Spending per sh 6.75 23.01 22.54 23.88 24.04 25.77 36.84 38.85 40.88 42.74 44.65 46.40 48.15 Book Value per sh c 53.25 38.02 38.34 42.22 42.66 43.63 50.23 50.27 50.34 50.40 50.42 50.40 50.40 Common Shs Outst'g u 50.40 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 16.2 19.1 20.6 Bold fig res are AvgAnn'I PIE Ratio 16.0 1.03 1.51 .82 .89 .82 .97 .84 .68 .75 .72 .79 .75 .77 .82 1.00 1.04 Value Une Relative P/E Ratio .90 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% 3.1% 2.8% , 2.6% est/, lates Avg Ann'I Div'd Yield 4.0%
CAPITAL STRUCTURE as of 12/31/17 960.4 1049.8 1036.0 1026.8 1080.7 1246.2 1282.5 1270.3 1262.0 1349.5 1340 1360 Revenues ($mill) 1450 Total Debt $1746.1 mill. Due in 5 Yrs $305.D mill. 98.4 124.4 142.5 166.9 168.9 182.4 193.5 194.7 198.3 212.4 210 220 Net Profit ($mill) 245 LT Debt $1746.1 mill. LT lnteresl$82.D mill. 16.3% 15.2% -- -- 13.4% 28.3% 8.0% 19.0% 15.5% 18.6% 10.5% 10.5% Income Tax Rate 10.5%
(LT interest earned: 3.9x) 13.9% 14.0% 14.0% AFUDC %to Net Profit 14.0%
10.2% 10.5% 19.1% 23.3% 20.3% 12.3% 13.6% 16.3% 16.3%
Pension Assets-12/17 $697.7 mill. 47.6% 50.2% 49.3% 45.6% 45.5% 46.6% 45.3% 45.6% 44.8% 43.7% 44.0% 42.0% Long-Tenn Debt Ratio 44.0%
.Oblig $999.3 mill. 52.4% 49.8% 50.7% 54.4% 54.5% 53.4% 54.7% 54.4% 55.2% 56.3% 56.0% 58.0% Common Equity Ratio 56.0%
2485.9 2807.1 3020.4 3045.2 3225.4 3465.9 3567.6 3783.3 3898.5 3997.5 4180 4165 Total Capital ($mill) 4775 Pfd Stock None 2758.2 2917.0 3161.4 3406.6 3536.0 3665.0 3833.5 3992.4 4172.0 4283.9 4425 4560 Net Plant ($mill) 4850 Common Stock 50,392,360 shs. 5.3% 5.7% 6.0% 6.8% 6.5% 6.4% 6.6% 6.2% 6.1% 6.3% 6.0% 6.5% Return on Total Cap'I 6.0%
as of 2/16/18 7.6% 8.9% 9.3% 10.1% 9.6% 9.9% 9.9% 9.5% 9.2% 9.4% 9.0% 9.0% Return on Shr. Equity 9.0%
7.6% 8.9% 9.3% 10.1% 9.6% 9.9% 9.9% 9.5% 9.2% 9.4% 9.0% 9.0% Return on Com Equity E 9.0%
MARKET CAP: $4.5 billion (Mid Cap) 3.4% 4.8% 5.5% 6.5% 5.7% 5.6% 5.4% 4.8% 4.3% 4.4% 4.0% 4.0% Retained to Com Eq 3.5%.
ELECTRIC OPERATING STATISTICS 55% 46% 41% 36% 41% 43% 46% 50% 53% 53% 57% 59% All Div'ds to Net Prof 63%
%ChangeRetai1Sales(Kl',li) ~1~~ 20}~ ~ 21~ BUSINESS: IDACORP, Inc. is a holding company for Idaho Power rigation, 11%; other, 10%. Generating sources: hydro, 50%; coal, Avg.lnaust.Use(MWH) NA NA NA Company, a regulated electric utility that serves 545,000 customers 18%; gas, 8%; purchased, 24%. Fuel costs: 33% of revenues. '17 Avg.lndu~.Revs.:~(¢) 5.70 5.63 5.83 throughout a 24,DOO-square-mile area in southern Idaho and east- reported depreciation rate: 2.9%. Has 2,000 employees. Chairman:
Capacifya!Peak( ~
- (}i0t~ads~~~;r1i,) ) 34NA
~~
3 ~~NA
~~
34NA ern Oregon (population: 1 million). Most of the company's revenues
. are derived from the Idaho portion of its service area. Revenue Robert A. Tinstman. President & CEO: Darrel T. Anderson. ln-corporated: Idaho. Address: 1221 W. Idaho si., Boise, Idaho
%ChangeCustomers{yr-n~ +1.4 +1.8 +2.0 breakdown: residential, 41%; commercial, 24%; industrial, 14%; ir- 83702. Telephone: 208-388-2200. lntemet: www.idacorpinc.com.
F~edChargeCov.(%) 307 295 329 IDACORP's 10-year streak of earnings 2017 was driven in part by weather) due ANNUAL RATES Past Past Est'd ,15 _, 17 growth might well come to an end in to the effects of energy efficiency. The util-of change (persh) 10Yrs. svrs. to'21-'23 2018. This is despite the performance of ity's cost control has been effective, too.
Revenues 2.5% 4.0% 2.0% the company's utility subsidiary, Idaho We forecast a reslllilption of profit "Cash Flow" 5.5% 4.0% 4.5% Power, which is faring well, is financially growth in 2019. We think IDACORP will Bt7~l~~Js ~:~~ 1 6:~~ i:~~ sound, and has good growth prospects. A year ago, IDACORP's income benefited benefit from the growth of Idaho Power.
Our $4.35-a-share estimate would produce Book Value 5.5% 5.5% 3.5%
Cal- QUARTERLYREVENUES($mill.) Full from some tax adjustments. Favorable an increase of 5%.
endar Mar.31 Jun.30 Sep.30 Dec.31 Year weather conditions, helped, as well. Our The utility has a regulatory mechan-2015 279.4 336 _3 369 _2 285.4 1270_3 earnings estimate of $4.15 a share, which ism to supplement its income, if 2016 281.0 315.4 3?2.0 293 .6 1262.0 we trimmed by a nickel, is within the com- necessary. If Idaho Power's earned re-2017 302.6 333.0 408.3 305.6 1349.5 pany's targeted range . of $4.10-$4.25. turn on equity falls below 9.5% through 2018 310 335 390 305 1340 Given that IDACORP earned $4.21 a 2019, the utility may use up to $25 million 2019 315 340 395 310 1360 share in 201 7, another year of profit of accumulated deferred investment tax Cal- EARNINGS PER SHARE A Full growth is hardly out of the question, based credits annually to bring its ROE to that endar Mar.31 Jun.30 Sep.30 Dec.31 Year on the company's guidance. . level. (A proposed regulatory settlement m~
2017
- ~i
.66 ni
.99
-1:ci~
1.80
- ~~
.77 u~ ::. :~:c\rd~':!:fn!sgr;:!~i: isc~:::: ;:y~~d 0
4.21 rupted. Management anticipates recom- shown in the* statistical array are for e'::;d ;~~~-) m~~~:n~1:t i~~=fi~~~{
2018 .60 1.00 1.85 .70 4.15 mending to the board annual increases of IDACORP as a whole, not just its utility 2019 .65 1.05 1.90 .75 4.35 at least 5%. The company is targeting a subsidiary.
Cal- QUARTERLYDIVIDENDSPAIDB*t Full payout ratio in a range of 50%-60%. This stock is timely, but is priced ex-endar Mar.31 Jun.30 Seo.30 Dec.31 Year Idaho Power is performing well. The pensively. The dividend yield is below
. economy of the company's service area is average for a utility. The recent quotation 2014 43 43 43 47 1 76 2015 :47 :47 :47 :51 1_92 healthyh. _Chustomer grhowthd wba s 2h.O~ dlast Tis nearpthe uRpper enAd ofdour 2021-2 023 2016 .51 .51 .51 .55 2.08 year, w 1c is more t an ou 1e t e m us- arget rice ange. ccor ing1y, tota1 re-2017 .55 .55 .55 .59 2.24 try norm. Kilowatt-hour sales generally turn potential is negligible.
2018 .59 aren't rising as fast (the 2.6% increase in Paul E. Debbas, CFA April 27, 2018 (A) Diluted EPS. Exel. nonrecurring gains paid in late Feb., May, Aug., and Nov.
- Div'd Net original cost. Rate allowed on common Company's Financial Strength A (loss): '03, 26¢; '05, (24¢); '06, 17¢. '17 earn- reinvestment plan available. t Shareholder in- equity in '11: 10% (imputed); earned on avg. Stock's Price Stability 95 ings don't sum due to rounding. Nexl earnings vestment plan available. (C) Incl. intangibles. In com. eq., '17: 9.6%: Regulatory Climate: Price Growth Persistence 90 report due early May. (8) Div'ds historically '17: $21.49/sh. (D) In millions. (E) Rate base: Above Average. Earnings Predictability 95 ~
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wtthout warranties of any kind. 1 THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscribe(s own, non-commercial, internal use. No part* **1-..., 11 1 ,w .. , " : 11 of tt may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product:
L.J\,,H\,,UU.I.\,, ~.1..1.'U - J 18-KCPE-480-RTS --
NORTHWESTERN NYSE-NWE IRECENT PRICE 54 ,59 IP/ERATIO 16 , 2Crailing:16.3)
Median: 16.0 RELATIVE PIE RATIO O86 DIV'YLDD 4.1%-
I TIMELINESS 3 Lowered 2/23118 High:
Low:
36.7 24.5 29.7 16.5 26.8 18.5 30.6 23.8 36.6 27.4 38.0 33.0 47.2 35.1 58.7 42.6 59.7 48.4 63.8 52.2 64.5 55.7 59.8 50.0
.,, Target Price Range 2021 2022 2023 SAFETY 3 New5/4/12 LEGENDS 120 TECHNICAL 5 Lowered 416/18 - ~Ji1~ ~vi1~t~~!l ~~ta
. , , . Relative Price Strength 100
...... - .......... 80 BETA .65 (1.00 = Market) tUtl*23 IIUN:)
o~~~~:/:ia indicates recession I/"'--.. ..... ~ *** 1r*11
.... ,.. ,., .... ~oil r,4.. -
64 48 Ann'I Total Price Gain Return ........... /.', ... ,1*11,,, 11111111 I High 75 (+35%1 11%
..... .. *11' .. 1I 32 1111111 Low 50 (-10% 2% .ui-~ 11 111 I
. . .... 24 Insider Decisions J J A S 0 N D J F
- ...... 11
"'"I
... -** . 20 16 to Buy 0 0 0 0 0 0 0 0 0 Options 1 0 1 0 0 1 0 215 to Sall 0 0 1 1 0 0 1 0 1
- % TOT. RETURN 3/18 12 Institutional Decisions -8 THIS VLARITll' to Buy 2Q2017 124 101 3Q2017 118 100 4Q2017 96 97 Percent shares 30 20 I
1 yr.
3yr.
STOCK
-4.9 11.4 INDEX 9.7 24.3 --
to Soll Hld's(DDD) 56186 53930 45947 traded 10
- II. lh I 11111111111111m1111111111111 1111111111 11,111(1111 11111111111 1111111111
.II II 1111111111111111111m1 II II 5yr. 61.2 68.8 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 (£) VALUE LINE PUB. LLC 1, 1-23
.. .. 29.18 32.57 31.49 30.79 35.09 31.72 30.66 30.80 28.76 29.80 25.68 25.21 26.01 26.45 26.25 27.00 Revenues per sh 29.50
.. .. 3.20 4.00 3.62 3.70 4.40 4.62 4.76 5.42 5.18 5.45 5.39 5.92 6.74 6.76 6.95 7.30 "Cash Flow" per sh 8.25
.. .. d14.32 1.71 1.31 1.44 1.77 2.02 2.14 2.53 2.26 2.46 2.99 2.90 3.39 3.34 3.45 3.55 Earnings per sh A 4.00
.. .. .. 1.00 1.24 1.28 1.32 1.34 1.36 1.44 1.48 1.52 1.60 1.92 2.00 2.10 2.20 2.30 Div'd Decl'd per sh a* t 2.60
.. .. 2.25 2.26 2.81 3.00 3.47 5.26 6.30 5.20 5.89 5.95 5.76 5.89 5.96 5.60 5.70 6.70 Cap'I Spending per sh 6.25
.. .. 19.92 20.60 20.65 21.12 21.25 21.86 22.64 23.68 25.09 26.60 31.50 33.22 34.68 36.44 37.95 39.10 Book Value per sh c 42.75
.. .. 35.60 35.79 35.97 38.97 35.93 36.00 36.23 36.28 37.22 38.75 46.91 48.17 48.33 49.37 50.25 50.4() Common Shs Outst'g 0 51.00
.. .. .. 17.1 26.0 21.7 13.9 11.5 12.9 12.6 15.7 16.9 16.2 18.4 17.2 17.8 Bo/rt fig res are Avg Ann'I P/E Ratio 16.0
.. .. .. .91 1:40 1.15 .84 .77 .82 .79 1.00 .95 .85 .93 .90 .89 Value Line Relative P/E Ratio .90
.. .. .. 3.4% 3.6% 4.1% 5.4% 5.7% 4.9% 4.5% 4.2% 3.7% 3.3% 16% 3.4% 3.5%
estin [ales Avg Ann'I Div'd Yield 4.1%
CAPITAL STRUCTURE as of 12/31/17 1260.8 1141.9 1110.7 1117.3 1070.3 1154.5 1204.9 1214.3 1257.2 1305.7 1320 1360 Revenues ($mill) 1500 Total Debt $2137.3 mill. Due In 5 Yrs $332.0 mill. 67.6 73.4 77.4 92.6 83.7 94.0 120.7 138.4 164.2 162.7 170 180 Net Profit ($mill) 205 LT Debt $1815.6 mill. LT Interest $83.5 mill. 37.3% 17.2% 25.0% .. 13.7%
9.8% 9.6% 13.2% 13.7% 7.6% 2.5% 3.5% Income Tax Rate 6.5%
Incl. $22.2 mill. capitalized leases.
(LT interest earned: 3.1 x) 2.3% 4.4% 14.2% 3.3% 9.4% 8.7% 8.9% 9.8% 4.3% 5.2% 6.0% 6.0% AFUDC %to Net Profit 5.0%
46.8% 56.4% 57.2% 52.2% 53.8% 53.5% 53.4% 53.1% 52.0% 50.2% 49.5% 48.5% Long-Tenn Debt Ratio 46.0%
53.2% 43.6% 42.8% 47.8% 46.2% 46.5% 46.6% 46.9% 48.0% 49.8% 50.5% 51.5% Common Equity Ratio 54.0%
Pension Assets-12/17 $586.5 mill. 1434.3 1803.9 1916.4 1797.1 2020.7 2215.7 3168.0 3408.6 3493.9 3614.5 3775 3840 Total Capital ($mill) 4()50 Oblig $696.8 mill.
1839.7 1964.1 2118.0 2213.3 2435.6 2690.1 3758.0 4059.5 4214.9 4358.3 4465 4620 Net Plant ($mill) 4975 Pfd Stock None 7.0% 6.0% 5.9% 7.0% 5.5% 5.5% 4.8% 5.2% 5.9% 5.6% 5.5% _5.5% Return on Total Cap'I 6.0%
Common Stock 49,397,196 shs. 8.9% 9.3% 9.4% 10.8% 9.0% 9.1% 8.2% 8.6% 9.8% 9.0% 9.0% 9.0% Return on Shr. Equity 9.5%
as of 2/9/18 8.9% 9.3% 9.4% 10.8% 9.0% 9.1% 8.2% 8.6% 9.8% 9.0% 9.0% 9.0% Return on Com Equity E 9.5%
MARKET CAP: $2.7 billion (Mid Cap) 2.3% 3.2% 3.5% 4.7% 3.2% 3.5% 3.8% 3.0% 4.1% 3.4% 3.5% 3.5% Retained to Com Eq 3.5%
ELECTRIC OPERATING STATISTICS 74% 66% 63% 56% 65% 61% 54% 65% 58% 62% 64% 64% All Div'ds to Net Prof 64%
2015 2016 2017 BUSINESS:
%Chaie Retail Sales (KVv!i) -.1 -.7 +3.8 NorthWestern Corporation (doing business as North- 5%; other, 4%. Generating sources: hydro, 36%; coal, 29%; wind, Avg. In ust. Use (MWH~ 30133 29784 30987 Western Energy) supplies electricity & gas in the Upper Midwest 6%; other, 4%; purchased, 25%. Fuel costs: 31% of revenues. '17 Avg.lndust.Revsifi;; (¢) NA NA NA and Northwest, serving 433,000 electric customers in Montana and reported deprec. rate: 3.0%. Has 1,600 employees. Chairman:
Capacity at Peak ) NA NA NA South Dakota and 286,000 gas customers in Montana (87% of Stephen P. Adik. President & CEO: Robert C. Rowe. Inc.: Dela-Peak load, Wn1er (Mw) 2096 2138 2133 Annual Load Factor(%& NA NA NA gross margin), South Dakota (12%), and Nebraska (1 %). Electric ware. Address: 301 O West 69th Street, Sioux Falls, South Dakota
%Change Cu~omers r~nd) +1.3 +1.2 +1.3 revenue breakdown: residential, 40%; commercial, 51 %; industrial, 57108. Tel.: 605-978-2900. Internet: www.northwesternenergy.com.
F~ed Charge Cov. (%) 252 253 275 We estimate that NorthWestern's wholesale customers (versus the compa-ANNUAL RATES Past Past Est'd '15-'17 earnings will advance moderately this ny's request for a 20% allocation). This of change (per sh) 10Yrs. 5Yrs. to '21-'23 year. In 2018, the company will benefit forced NorthWestern to take a $0.12-a-Revenues -2.0% -3.0% 2.0% from a full year's effect of a $5.1 million share charge in 2012. Management is "Cash Flow 5.5% 5.0% 4.0% gas rate hike that took effect in Montana deciding whether pursuing this matter Earnings 8.0% 7.0% 3.5%
Dividends 5.5% 7.0% 4.5% last September. The refinancing of debt in further is worthwhile.
Book Value 5.5% 8.0% 3.5% the fourth quarter of 2017 is another plus. Another legal matter is pending. The Cat- QUARTERLY REVENUES ($ mill.) However, there will be some dilution from Montana commission disallowed recovery Full endar Mar.31 Jun.JO Sep.JO Dec.31 Year the equity issued in 2017 and 2018 via its of certain costs associated with a plant 2015 346.0 270.6 272.7 325.0 1214.3 at-the-market program. Our 2018 share- outage in 2013. This forced NorthWestern 2016 332.5 293.1 301.0 330.6 1257.2 earnings estimate, which we trimmed by to take a $0.13-a-share charge in the 2016.
2017 367.3 283.9 309.9 344.6 1305.7 $0.05 a share, is within NorthWestern's The utility is seeking relief in the Montana 2018 365 300 315 340 1320 targeted range of $3.35-$3.50. District Court. It expects a decision within 2019 375 310 325 350 1360 An electric rate case is upcoming in the next 12 months.
Cal- EARNINGS PER SHARE A Full Montana. The utility expects to file an ap- The board of directors raised the divi-endar Mar.J1 Jun.JO Sep.JO Dec.J1 Year plication by September, with an order due dend in the first quarter. The hike was 2015 1.09 .38 .51 .93 2.90 by mid-2019. NorthWestern has some. as- $0.10 a share (4.8%) annually, the same as 2016 .82 .73 .92 .92 3.39 sets that are not reflected in rates. How- a year earlier. NorthWestern is targeting a 2017 1.17 .44 .75 .98 3.34 ever, regulation in Montana has worsened payout ratio in a range of 60%-70%.
2018 1.15 .45 .80 1.05 .3.45 in recent years, which is a cause for con- This stock has a dividend yield and 3-2019 1.20 .45 .85 1.05 3.55 cern. Still, a partial year of rate relief to 5-year total return potential that Cal- QUARTERLY DIVIDENDS PAID a* t Full would benefit earniifs in 2019. are above the utility average. This fol-endar Mar.31 Jun.30 Seo.30 Dec.31 Year NorthWestern ha a setback in the lows a price decline of more than 10%
2014 .40 .40 .40 .40 1.60 U.S. Court of Appeals. The utility ap- since the start of 2018. This has been a 2015 .48 .48 .48 .48 1.92 pealed an unfavorable ruling from the bad year for utility equities, but the falloff 2016 .50 .50 .50 .50 2.00 Federal , Energy Regulatory Commission, has been greater than most in this indus-2017 .525 .525 .525 .525 2.10 which ruled that just 4% of the cost of a try. There isn't a clear reason why.
2018 .55 gas-fired plant could be allocated to Paul E. Debbas, CFA April 27, 2018 (A) D!luted EP~. Exel. gain (loss). on discont. (B) Div'ds historiC!!IIY p~id in late Mar., June, on com. eq. in MT in '14 (elec.): 9.8%_; in '1.7 Company'~ Financ_i~I Strength B+
ops.: 05, (6¢); 06, 1¢; nonrec. gains: '12, 39¢ Sept. & Dec.
- D1v'd reinvestment plan avail. (gas): 9.55%; in SD 1n '15: none specified; 1n Stock's Pnce Stab1lrty 95 net; '15, 27¢. '15. EPS don't add due to round- (C) Incl. defd charges. In '.17: $14.42/sh. (D) In NE in '07: 10.4%; earned on avg. com. eq., '17: Pric~ Growth ~ersi~t.ence 85 1ng. Next earnings report due late July. mill. (E) Rate base: Net orig. cost. Rate allowed 9.5%. Regulatory Climate: Below Average.* Earnings Predrctabrlrty 85 .~ .
© 2018 Value Line, Inc. All rights reseived. Factual material is obtained from sources believed to be reliable and is provided without warranties of anN kind.*- ;
THE PUBLISHER IS NOT RESPONSIBLE FOR AflY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. o part; I I I ' * *I I '
of tt may be reproduced, resold, stored or transmitted in anyprinted, electronic or other form, or used for generatin or ma1keting any printed or electronic ublication, seivice or product
18-KCPE-480-RTS 34 ,32 IP/ERATIO 16,7(Trailing: 17.1) RELATIVE Q91 DIV'D OGE ENERGY CORP. NYSE-OGE RECENT IPRICE Median: 16.0 P/E RATIO , YLD 4.3%
3 Raised 6/1/18 High: 20.7 18.1 18.9 23.1 28.6 30.1 40.0 39.3 36.5 34.2 37.4 35.4 Target Price Range TIMELINESS Low: 14.6 9.8 9.9 16.9 20.3 25.1 27.7 32.8 24.2 23.4 32.6 29.6 2021 2022 2023 SAFETY 2 Lowered 12/18/15 -
LEGENDS 0.76 x Dividends p sh TECHNICAL 4 Raised 6/15/18 l--+---l---+---+---+--+---+----11---+---l---+- --!-----1--+80
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67.5 1-0 ""VA""LU=E.,..,Ll=NE'""P=UB,....,,L.,..,LC..,.1,,..,1'""*2=3-l 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 11.00 11.31 11.32 12.25 13.00 Revenues per sh 15.25 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 3.23 3.31 3.34 3.55 4.00 "Cash Flow" per sh 4.75
.72 .87 .89 .92 1.23 1.32 1.25 1.33 1.50 1.73 1.79 1.94 1.98 1.69' 1.69 1.92 2.05 2.15 Earnings per sh A 2.50
.67 .67 .67 .67 .67 .68 .70 .71 .73 .76 .BO .85 .95 1.05 1.16 1.27 1.40 1.54 Div'd Decl'd per sh B
- 1.85 1.49 1.04 1.51 1.65 2.67 3.04 4.01 4.37 4.36 6.48 5.85 4.99 2.86 2.74 3.31 4.13 3.15 3.15 Cap'I Spending per sh 2.75 6.27 6.87 7.14 7.59 8.79 9.16 10.14 10.52 11.73 13.06 14.00 15.30 16.27 16.66 17.24 19.28 19.90 20.50 Book Value per sh c 22.75 157.00 174.80 180.00 181.20 182.40 183.60 187.00 194.00 195.20 196.20 197.60 198.50 199.40 199.70 199.70 199.70 199.70 199.70 Common Shs Outst'g 0 199.70 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 17.7 17.7 18.3 Bold fig res are Avg Ann'I P/E Ratio 17.0
.77 .67 .74 .79 .74 .73 .75 .72 .85 .90 .97 .99 .96 .89 .93 .91 Value Una Relative PIE Ratio .95 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% 3.5% 3.9% 3.6% estin ~es Avg Ann'I Div'd Yield 4.3%
CAPITAL STRUCTURE as of 3/31/18 4070.7 2869.7 3716.9 3915.9 3671.2 2867.7 2453.1 2196.9 2259.2 2261.1 2450 2600 Revenues ($mill) 3050 Total Debt $3193.7 mill. Due in 5 Yrs $694.4 mill. 231.4 258.3 295.3 342.9 355.0 387.6 395.8 337.6 338.2 384.3 405 425 Net Profit ($mill) 520 LT Debi $2500.1 mill. LT Interest $119.8 mill. 30.4% 31.7% 34.9% 30.7% 26.0% 24.9% 30.4% 29.2% 30.5% 32.5% 15.5% 15.5% Income Tax Rate 15.5%
(LT interest earned: 4.3x) 3.0%
1.7% 9.1% 5.7% 9.0% 2.7% , 2.6% 1.7% 3.7% 6.4% 15.0% 8.0% 7.0% AFUDC %to Net Profit Leases, Uncapitalized Annual rentals $4.8 mill. 53.3% 50.6% 50.8% 51.6% 50.7% l\3.1% 45.9% 44.3% 41.1% 41.7% 43.0% 44.0% Long-Tenn Debt Ratio 45.5%
46.7% 49.4% 49.2% 48.4% 49.3% 56.9% 54.1% 55.7% 58.9% 58.3% 57.0% 56.0% Common Equity Ratio 54.5%
Pension Assets-12/17 $635.3 mill. 4058.6 4129.7 4652.5 5300.4 5615.B 5337.2 5999.7 5971.6 5849.6 6600.7 6975 7345 Total Capital ($mill) 8275 Oblig $687.5 mill. 5249.8 5911.6 6464.4 7474.0 8344.B 6672.B 6979.9 7322.4 7696.2 8339.9 8660 8910 Net Plant ($mill) 9450 Pfd Stock None 7.0% 7.0% 7.0% 7.0% Return on Total Cap'I 7.5%
7.0% 7.9% 7.8% 7.8% 7.7% 8.6% 7.8% 6.9%
Common Stock 199,731,036 shs. 12.2% 12.7% 12.9% 13.4% 12.8% 12.8% 12.2% 10.2% 9.8% 10.0% 10.0% 10.5% Return on 5hr. Equity 11.5%
12.2% 12.7% 12.9% 13.4% 12.8% 12.8% 12.2% 10.2% 9.8% 10.0% 10.0% 10.5% Return on Com Equity E 11.5%
MARKET CAP: $6.9 billion (Large Cap) 5.4% 6.0% 6.7% 7.7% 7.2% 7.3% 6.5% 4.0% 3.3% 3.5% 3.0% 3.0% Retained to Com Eq 3.5%
ELECTRIC OPERATING STATISTICS 55% 53% 48% 43% 44% 43% 47% 61 % 67% 64% 69% 72% All Div'ds to Net Prof 71%
- 2015 2016 ~i~ 1-=B~U~Sl~N~E7SS~:~O~G~E~E~n-e-~~y-C-or-p-.i~s-a_h_o~ld~in-g-co_m_p~an-y~f~or-O~k~la~h-o--+i-ng_s_o_ur~re-s-:-co-a~l.-34-o/c-,;-g~as-.-2~5%~,;~w~in-d-,-4%-,;-p-u-rc-ha-s-ed-,-37~%-,.-F-u-el~
%Change Retail Sales (KWH) *2.9 -1.1 Avg. lnlfust. Use (MWHl 754 NA NA ma Gas and Electric Company (OG&E), which supplies electricity to costs: 40% of revenues. '17 reported depreciation rate (utility):
Avg.lndust.Revsyerl(\Ml(¢) 5.05 5.17 5.30 842,000 customers in Oklahoma (84% of electric revenues) and 2.5%. Has 2,400 employees. Chairman, President and Chief Exec-Capali1ya1Peak(Mwl NA NA NA western Arkansas (8%); wholesale is (8%). Owns 25.6% of Enable utive Offirer: Sean Trauschke. Incorporated: Oklahoma. Address:
Peak load, Summer !Mw) 6537 6538 6~ Midstream Partners. Electric revenue breakdown: residential, 40%; 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-Annual Load Factor(Y,) NA NA
%Change Customers ~r-n~ +1.2 +1.1 1----=-=-------------------....;,..__________. .:. .____
+1.0 commercial, 26%; industrial, 9%; oilfield, 7%; other, 18%. General- 0321. Telephone: 405-553-3000. Internet: www.oge.com. --I F~edChargeCov.(%) 314 336 315 OGE Energy's utility subsidiary has a will not have to file a general rate case to 1-A-N_N_U_A~L-RA~T~ES--P-as-t--P-a-st-E-st-'d-,- -_,---i general rate case pending. Oklahoma recover its major capital projects. Instead, 15 17 of change (per sh) 10 Yrs. 5Yrs. to '21-'23 Gas and Electric filed for a hike of $1. 9 OG&E will recover them through various Revenues -8.0% -10.0% 5.5% million, based on a 9.9% return on a 53% regulatory mechanisms, such as a formula
~~~i~;iow" 1:g~ .;:8~ i.i~ common-equity ratio. The requested rate plan it will file in October.
amount is small because it reflects the ef- We estimate respectable earnings Dividends 5.5% 8.5% 8.0%
Book Value 7.5% 6.5% 4.0% fects of the new federal tax law; without growth this year and next. OG&E will QUARTERLY REVENUES ($ mill.)
tax reform, OG&E would have sought over benefit from rate relief, assuming reason-Cal- Full to place a able regulatory treatment from the Okla-endar Mar.31 Jun.30 Sep.30 Dec.31 Year $70 million. The company wants
$390 million project to modernize a gas- homa. commission. The lower tax rate ap-2015 480.1 549.9 719.8 447.1 2196.9 fired plant in rates; raise the depreciation plied to OGE Energy's income from its 2016 433.1 551.4 743.9 530.8 2259.2 2017 456.0 586.4 716.8 501.9 2261.1 rate; and boost its allowed ROE from the stake in Enable Midstream Partners will 2018 492.7 625 782.3 550 2450 current 9.5%. The staff of the Oklahoma add an estimated $0.08 to share net this 2019 525 675 825 575 2600 commission recommended a $43 million year. Our 2018 estimate is at the upper EARNINGS PER SHARE A reduction, based on a 8.75% return on a end of the company's targeted range of Cal* Full endar Mar.31 Jun.JO Sep.30 Dec.31 Year 53% common-equity ratio, and the state $1.90-$2.05.
.22 .44 1.69 attorney general proposed a $99 million OGE Energy stock is attractive for 2015 .88 .15 2016 .13 .35 .92 .29 1.69 cut, based on a return of 9.18% on a income-oriented accounts. The divi-2017 .18 .52 .92 .30 1.92 common-equity ratio of 50%. New rates dend yield is above average, even by utili-2018 .27 .50 1.00 .28 2.05 are expected to take effect at the start of ty standards. In addition, management ex-2019 .20 .55 1.10 .30 2.15 October. pects the board to raise the disbursement QUARTERLY DIVIDENDS PAID a
- Full Additional regulatory matters are up- by 10% in each of 2018 and 2019, as the Cal-endar Mar.31 Jun.30 Seo.JO Dec.31 Year coming. OG&E plans to file another rate distributions OGE Energy receives from application in December, with new tariffs Enable are a good source of cash. Rapid 2014 .225 .225 .225 .25 .93 driver dividend growth should continue beyond 2015 .25 .25 .25 .275 1.03 taking effect in mid-2019. The main 2016 .275 .275 .275 .3025 1.13 of this case will be a $542 million project 2019, though not necessarily at the 10%
2017 .3025 .3025 .3025 .3325 1.24 to install pollution-control equipment at a level.
2018 .3325 .3325 coal-fired plant. In Arkansas, the utility Paul E. Debbas, CFA June 15, 2018 (A) Dil. EPS. Exel. nonrecur. gain (losses): '02, historically paid in late Jan., Apr., July, &Oct.* Rate allowed on com. eq. in OK in '16: 9.5%; in Company's Financial Strength A (20¢); '03, (7¢); '04, (3¢); '15, (33¢); '17, $1.18; Div'd reinvestment plan available. (C) Incl. de- AR in '11: 9.95%; earned on avg. com. eq., '17: Stock's Price Stability 90 gains on disc. ops.: '02, 6¢; '05, 25¢; '06, 20¢. ferred charges. In '17: $1.42/sh. (D) In mill., 10.9%. Regulatory Climate: Average. Price Growth Persistence 50 Next earnings report due early Aug. (B) Div'ds adj. for split. (E) Rate base: Net original cost. Earnings Predictability 75*~
© 2018 Value Line, Inc. All rights reserved. Factual material is obtain.ad from sources believed to be reliable and is provided wtthout warranties of any kind.' - 1 THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part I I I *
- l~:!1111'111 111 of nmay be reproduced, resold, s1ored or 1ransmnted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product
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Raised5/3/13 Lowered4/6/18 High: 51.7 42.9
'-'-L~o~w~:~-36_._8~_26_.3~~22.3 LEGENDS 38.0 42.7 32.3 48.9 37.3 l:""T'"no_18__,.1___(~_~~i-,- i~~;l_U)-+-~_TE~--,r,i_o_.9,-16l_~~D_3--,.6°___[~
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~::d~vi1~t~~:.r ~~le 1--+---+--+----1--+----1--+---+---+---+--+---+--+---+-100 61.9 51.5 71.1 51.2 73.3 56.0 82.8 62.5 92.5 75.8 85.6 73.8
I 18-KCPE-480-RTS
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toSuy 194 218 182 shares 20 1 yr. -1.2 9.7 _
to Sell 224 Hld's(DDDI 107032 104825 94333 185 183 traded 10 '" "'1nttffl "" ,. * * " *1111111111111111111 II,,
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39.0 65.3 24.3 68.8 i-;2;:;,0~02~2='=0,:,;0'="3-r2""'0="0""4"T":'20:i:,o:ei:5.-h:2=oo""'s,..,..,.2=0=07::'lf'!,200s 2009 2010 2011 2012 2013 2014 2015 2:H/0~16,!II/J,!2l'!,Ou,&,17~2!:-,0,.,,1=s"'-=20""'1=9+-@"",v.=A""'Lu=-E""LIN=E""'Pu=s.....L,...,LC"",,1.,,1...,.-2"'"3-l 28.90 30.87 31.59 30.16 34.03 35.07 33.37 32.50 30.01 29.67 30.09 31.35 31.58 31.50 31.42 31.90 32.80 34.30 Revenues per sh 39.75 7.01 7.33 6.93 5.76 9.70 9.29 8.13 8.08 6.85 7.52 7.92 8.15 8.09 9.09 9.39 9.79 10.10 10.65 "Cash Flow" per sh 12.75 2.53 2.52 2.58 2.24 3.17 2.96 2.12 2.26 3.08 2.99 3.50 3.66 3.58 3.92 3.95 4.43 4.50 4.70 Earnings per sh A 5.50 1.63 1.73 1.83 1.93 2.03 2.10 2.10 2.10 2.10 2.10 2.67 2.23 2.33 2.44 2.56 2.70 2.86 3.02 Div'd Decl'd per sh e
- 3.50 9.81 7.60 5.86 6.39 7.59 9.37 9.46 7.64 7.03 8.26 8.24 9.36 8.38 9.84 11.64 12.80 11.25 10.80 Cap'I Spending per sh 11.00 29.44 31.00 32.14 34.57 34.48 35.15 34.16 32.69 33.86 34.98 36.20 38.07 39.50 41.30 43.15 44.80 46.35 48.00 Book Value per sh c 54.00 91.26 91.29 91.79 99.08 99.96 100.49 100.89 101.43 108.77 109.25 109.74 110.18 110.57 110.98 111.34 111.75 112.00 112.25 Common Shs Outst'g 0 113.00 14.4 14.0
- 15.8 19.2 13.7 14.9 16.1 13.7 12.6 14.6 14.3 15.3 15.9 16.0 18.7 19.3 Bold fig res are Avg Ann I P/E Ratio 15.0
.79 .80 .83 1.02 .74 .79 .97 .91 .80\ .92 .91 .86 .84 .81 .98 .97 Value Line Relative PIE Ratio .85 estlniates 4.5% 4.9% 4.5% 4.5% 4.7% 4.8% 6.2% 6.8% 5.4% 4.8% 5.3% 4.0% 4.1% 3.9% 3.5% 3.2% Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUCTURE as of 12/31/17 3367.1 3297.1 3263.6 3241.4 3301.8 3454.6 3491.6 3495.4 3498.7 3565.3 3675 3850 Revenues ($mill) 4500 Total Debl$4829.4 mill. Due in 5 Yrs $1188.4 mill. 213.6 229.2 330.4 328.2 387.4 406.1 397.6 437.3 442.0 497.8 505 535 Net Profit ($mill) 630 LT Debt $4789.7 mill. LT Interest $213.6 mill. 23.4% 36.9% 31.9% 34.0% 36.2% 34.4% 34.2% 34.3% 33.9% 32.5% 18.0% 18.0% Income Tax Rate 18.0%
Incl. $13.4 mill. Palo Verde sale leaseback lessor notes. 17.5% 11.2% 11.7% 12.8% 9.7% 10.0% 11.6% 11.8% 14.1% 13.9% 13.0% 10.0% AFUDC %to Net Profit 8.0%
(LT interest earned: 4.4x) 46.8% 50.4% 45.3% 44.1% 44.6% 40.0% 41.0% 43.0% 45.6% 48.9% 48.0% 48.5% Long-Tenn Debt Ratio 45.5%
Leases, Uncapitalized Annual rentals $13.4 mill. 53.2% 49.6% 54.7% 55.9% 55.4% 60.0% 59.0% 57.0% 54.4% 51.1% 52.0% 51.5% Common Equity Ratio 54.5%
Pension Assets-12/17 $3057.0 mill. 6477.6 6686.6 6729.1 6840.9 7171.9 6990.9 7398.7 8046.3 8825.4 9796.4 9985 10480 Total Capital ($mill) 11175 Oblig $3394.2 mill. 8916.7 9257.8 9578.8 9962.3 10396 10889 11194 11809 12714 13445 14075 14625 Net Plant ($mill) 16125 Pfd Stock None 4.7% 4.8% 6.5% 6.4% 6.8% 7.1% 6.4% 6.4% 6.0% 6.1% 6.0% 6.0% Return on Total Cap'I 6.5%
Common Stock 111,799,789 shs. 6.2% 6.9% 9.0% 8.6% 9.8% 9.7% 9.1% 9.5% 9.2% 9.9% 10.0% 10.0% Return on Shr. Equity 10.5%
as of 2/16/18 6.2% 6.9% 9.0% 8.6% 9.8% 9.7% 9.1% 9.5% 9.2% 9.9% 10.0% 10.0% Return on Com Equity E 10.5%
MARKET CAP: $9.0 billion (Large Cap) .3% .7% 3.1% 2.8% 4.1% 4.1% 3.5% 3.9% 3.5% 4.2% 3.5% 3.5% Retained to Com Eq 4.0%
ELECTRIC OPERATING STATISTICS 96% 89% 66% 68% 58% 58% 62% 59% 62% 58% 63% 63% All Div'ds to Net Prof 63%
%Change Retail Sales (KW!i)
. 2015
+1.3 2016
+.3 20 !~ *1--B-U-SI_N....ES_S_:_P-in....na_c_le_W_e.._s_tC-a-p-ita"'"1-c-or-po_r...at-io-n-is_a.._h_o_ld-ing_,_co_m_p-a-_,_c_o_m_m_e....rc-ia-l,-40_%....,;_i-nd-u-st...ria-1,-5-%-,;"'"o-th-e-r,-5-%-.-G-en-e-ra-ti-ng_..so-u-rc-es-:-t Avg. lnlfust. Use (Ml'llff 658 640 620 ny for Arizona Public Service Company (APS), which supplies elec- nuclear, 29%; gas & other, 26%; coal, 22%; purchased, 23%. Fuel Avg.lndust.Revs1.erl(\l,li(¢) 8.17 8.37 8.34 tricity to 1.2 million customers in most of Arizona, except about half costs: 28% of revenues. '17 reported deprec. rate: 2.8%. Has 6,300 Capacitya!Peak(MWl 9250 9192 8438 of the Phoenix metro area, the Tucson metro area, and Mohave employees. Chairman, President & CEO: Donald E. Brandt. Inc.:
Peak Load, Summer (Mw) 7031 7051 36 Annual Load Factor(%) 48.3 48.0 ~6 ~ County in northwestern Arizona. Discontinued Suncor real estate AZ.. Address: 400 North Fifth St., P.O. Box 53999, Phoenix, AZ.
%Change Customers (yr-end) +1.3 +1.3 +1.8 subsidiary in '10. Electric revenue breakdown: residential, 50%; 85072-3999. Tel.: 602-250-1000. Internet: www.pinnaclewest.com.
1-------------------------------------------t F~edChargeCov.(%) 438 416 425 Pinnacle West's utility subsidiary has crease this year. Pinnacle West raised 1-A-N_N_U_,A._L_RA-'-'TE'-S--Pa_s_t--P-as_t_E-st-,d-,- -.,--1 15 17 asked the Arizona Corporation Coin- its 2018 earnings guidance by a dime a ofchange(persh) 10Yrs. 5Yrs. to'21-'23 Inission for a rate increase. Although share, to $4.35-$4.55, due largely because Revenues -.5% 1.0% 4.0% the rate order last year for Arizona Public the company raised its expectation for the "Cash Flow 1.5% 5.0% 5.0% Service froze base tariffs mid-2020, the Allowance for Funds Used During Con-Btrcl~R~s tg~ ~:g~ ~:g~ ruling also allowed APS to file for recovery struction, a noncash credit to income. Ad-Book Value 2.0% 4.0% 4.0% of an environmental project at the Four ditional expense-management initiatives Comers coal-fired station through a rider are another factor. We raised our estimate Cal-endar QUARTERLY REVENUES ($ mill.)
Mar.31 Jun.30 Sep.30 Dec.31 Full Year (surcharge) on customers' bills. The utility a by $0.10 share, to $4.50.
2015 671.2 890.7 1199.1 is .seeking an increase of $65 million We forecast higher profit growth in 734.4 3495.4 2016 677.2 915.4 1166.9 739.2 3498.7 (about 2%), and no change in the allowed 2019. The aforementioned rate rider 2017 677.7 944.6 1183.3 759.7 3565.3 return on equity of 10%. A decision is ex- should help.
- In addition, the utility's 2018 700 975 1225 775 3675 pected in time for the rider to take effect strong (and rising) customer growth rate is 2019 725 1025 1300 800 3850 at the start of 2019. The project should be stimulating modest kilowatt-hour sales Cal- EARNINGS PER SHARE A Full completed soon at a cost of $390 million. growth, despite the effects of energy ef-endar Mar.31 Jun.30 Sep.30 Dec.31 Year The costs that the company will incur this ficiency. Our $4.70-a-share earnings es-2015 .14 1.10 2.30 .37 3.92 year will be deferred for recovery begin- timate would produce an increase of 4% .
2016 .04 1.08 2.35 .47 3.95 ning next year under the rider. This untnnely stock has a dividend 2017 .21 1.49 2.46 .27 4.43 Another large capital project is under yield and 3- to 5-year total return 2018 .25 1.30 2.60 .35 4.50 construction. APS is building five gas- potential that are about average, by 2019 .25 1.35 2.70 .40 4.70 fired units and retiring two at an esti- utility standards. Perhaps conservative Cal- QUARTERLY DIVIDENDS PAID e
- Full mated cost of $500 million. This will in- investors will find this acceptable, given endar Mar.31 Jun.30 Seo.30 Dec.31 Year crease the utility's generating capacity by the equity's top-notch Safety rank and the 2014 .568 .568 .568 .595 2.30 290 megawatts. Costs associated with this company's high rating for Financial 2015 .595 .595 .595 .625 2.41 project will be deferred until APS recovers Strength. However, like most utility is-2016 .625 .625 .625 .655 2.53 these. in its next base rate increase, sues, the recent price is within our 2021-2017 .655 .655 .655 .695 2.66 presumably in mid-2020. 2023 Target Price Range .
2018 .695 We estnnate a Inodest earnings in- Paul E. Debbas, CFA April 27, 2018 (A) Diluted EPS. Exel. nonrec. gain (losses): '16 EPS don't sum due to rounding. Next earn- avail. (C) Incl. defd chgs. In '17: $14.34/sh. Company's Financial Strength A+
'02, (77¢); '09, ($1.45); '17, 8¢; gains (losses) ings report due early May. (B) Div'ds historical- (D) In mill. (E) Rate base: Fair value. Rate al- Stock's Price Stability 95 from disc. ops.: '05, (36¢); '06, 10¢; 'OB, 28¢; ly pd. in early Mar., June, Sept., & Dec. There lowed on com. eq. in '17: 10.0%; earned on Price Growth Persistence 70
'09, (13¢); '10, 18¢; '11, 10¢; '12, (5¢). '15 & were 5 declarations in '12.
- Div'd reinv. plan avg. com. eq., '17: 10.0%. Regul. Climate: Avg. Earnings Predictability 95~
© 2018 Value Line, Inc. All righls reserved. Factual malarial is oblained from sources believed to be reliable and is provided wtthout warranlies of any kind.'
TH.E PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is slriclly for subscriber's own, non-commercial, internal use. No part: I I' :111111111~111 of tt may be reproduced, resold, slored or transmnted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product;
L)l,.,Hl,.,UUll,., I"U. .LU - J 18-KCPE-480-RTS PORTLAND GENERAL NYSE-POR IRECENT PRICE 40 ,92 IP/ERATIO 18 ,4Crailing:17.9) RELATIVE O Median: 16.0 P/E RATIO I 98 IDIV'YLDD 3.5%fl:I 21.4 22.7 26.0 28.1 33.3 40.3 41.0 45.2 50.1 45.6
- Target Price Range TIMELINESS 4 Lowered 3/23/18 High:
Low:
31.3 25.5 27.7 15.4 13.5 17.5 21.3 24.3 27.4 29.0 33.0 35.3 42.4 39.0 2021 2022 2023 SAFETY 2 Raised 5/4/12 LEGENDS TECHNICAL 5 Lowered 4/20/18 -. . . . ~i~e~ i"i1;1~1!sf ~~te Relatwe Price Strength 80 60 BETA .65 (1.00 = Market)
O~~~~~/:!a indicates recession - ... 50 11111111*1 "U"l-23 t'KUJtl.llUN::i Ann'! Total - u.or 1*,,111 111 ,
40 I / 30 High Price Gain Return ,. ,1 111111 ., ' 25 50 9%
Low 35 Insider Decisions
(+20%1
(-15% 1% .. ****.. ~K
,1111111
- 111 11,11::* .. 11* "'
I 20 15 to Buy J J A S 0 N D J F 0 0 0 0 0 0 0 0 0 ./
/ I - **
- .......... ......**** ....*****" .......~-- ........** ......... *****-. .--****** 10 Options 10 O O10 O 0 0 0 5 -7.5 to Soll 0 0 0 0 0 0 0 0 1 % TOT. RETURN 3/18 Institutional Decisions I THIS VLARITH.'
2Q2017 3Q2017 4Q2017 Percent 21 I 11 I I I 1yr.
STOCK
-6.0 INDEX 9.7 11~~~[111 ]~~~1111~~ij~l l1~~~ijl ~ 1
- to Buy to Soll 147 112 122 118 136 shares 91 traded 14 11* 11 11 3yr. 19.9 24.3 --
7 II 5yr. 55.5 68.8 Hld'sJOOO) 88988 88359 81125 111111111111 2002 2003 2004 2005F 2006 2007 2012 2013 2014 2015 2016 2017 2018 2019 rs, VALUE LINE PUB. LLC 1-23
.. -- .. 23.14 24.32 27.87 27.89 23.99 23.67 24.06 23.89 23.18 24.29 21.38 21.62 22.54 22.70 23.50 Revenues per sh 25.75
.. -- .. 4.75 4.64 5.21 4.71 4.07 4.82 4.96 5.15 4.93 6.08 5.37 5.78 6.16 6.40 6.85 "Cash Flow" per sh 8.00
-- -- -* 1.02 1.14 2.33 1.39 1.31 1.66 1.95 1.87 1.77 2.18 2.04 2.16 2.29 2.20 2.35 Earnings per sh A 2.75
.. -- .. -* .68 .93 .97 1.01 1.04 1.06 1.08 1.10 1.12 1.18 1.26 1.34 1.42 1.50 Div'd Decl'd per sh 8
- t 1.80
-* -- -- 4.08 5.94 7.28 6.12 9.25 5.97 3.98 4.01 8.40 12.87 6.73 6.57 5.77 6.35 5.10 Cap'! Spending per sh 5.00
-- .. -- 19.15 19.58 21.05 21.64 20.50 21.14 22.07 22.87 23.30 24.43 25.43 26.35 27.11 27.85 28.70 Book Value per sh c 31.50
.. .. -- 62.50 62.50 62.53 62.58 75.21 75.32 75.36 75.56 78.09 78.23 88.79 88.95 89.11 89.25 89.40 Common Shs Outst'g " 90.00
.. -- .. .. 23.4 11.9 16.3 14.4 12.0 12.4 14.0 16.9 15.3 17.7 19.1 20.0 Bold fig res are Avg Ann'I P/E Ratio 15.5
.. -- .. -- 1.26 .63 .98 .96 .76 .78 .89 .95 .81 .89 1.00 1.01 Value Uno Relative PIE Ratio .85 estin ates
.. -- .. .. 2.5% 3.3% 4.3% 5.4% 5.2% 4.4% 4.1% 3.7% 3.3% 3.3% 3.1% 2.9% Avg Ann'! Div'd Yield 4.2%
CAPITAL STRUCTURE as of 12/31/17 1745.0 1804.0 1783.0 1813.0 1805.0 1810.0 1900.0 1898.0 1923:0 2009.0 2025 2100 Revenues ($mill) 2325 Total Debi $2426 mill. Due in 5 Yrs $460 mill. 87.0 95.0 125.0 147.0 141.0 137.0 175.0 172.0 193.0 204.0 195 210 Net Profit ($mill) 255 LT Debt $2426 mill. LT Interest $123 mill. 28.7% 28.8% 30.5% 28.3% 31.4% 23.2% 26.0% 20.7% 20.6% 25.3% 12.5% 12.5% Income Tax Rate 12.5%
Incl. $49 mill. capitalized leases. 8.8% 7.0% 5.0% AFUDC %to Net Profit 4.0%
17.2% 31.6% 17.6% 5.4% 7.1% 14.6% 33.7% 19.8% 16.6%
(LT interest earned: 3.1x)
Leases, Uncapitalized Annual rentals $9 mill. 46.2% 50.3% 53.0% 49.6% 47.1% 51.3% 52.7% 47.8% 48.4% 50.1% 47.0% 50.5% Long-Tenn Debt Ratio 48.5%
Pension Assets-12/17 $629 mill. 53.8% 49.7% 47.0% 50.4% 52.9% 48.7% 47.3% 52.2% 51.6% 49.9% 53.0% 49.5% Common Equity Ratio 51.5%
Oblig $869 mill. 2518.0 3100.0 3390.0 3298.0 3264.0 3735.0 4037.0 4329.0 4544.0 4842.0 4710 5190 Total Capital ($mill) 5500 Pfd Stock None 3301.0 3858.0 4133.0 4285.0 4392.0 4880.0 5679.0 6012.0 6434.0 6741.0 6930 6985 Net Plant ($mill) 7000 5.0% 4.5% 5.4% 6.2% 5.9% 5.1% 5.8% 5.4% 5.6% 5.5% 5.5% 5.5% Return on Total Cap'I 6.0%
Common Stock 89,114,522 shs.
as of 2/2/18 6.4% 6.2% 7.9% 8.8% 8.2% 7.5% 9.2% 7.6% 8.2% 8.4% 8.0% 8.5% Return on Shr. Equity 9.0%
6.4% 6.2% . 7.9% 8.8% 8.2% 7.5% 9.2% 7.6% 8.2% 8.4% 8.0% 8.5% Return on Com Equity E 9.0%
MARKET CAP: $3.6 billion (Mid Cap) 2.0% 1.5% 3.0% 4.1% 3.5% 2.9% 4.6% 3.3% 3.5% 3.6% 3.0% 3.0% Retained to Com Eq 3.5%
ELECTRIC OPERATING STATISTICS 69% 76% 62% 54% 57% 61% 50% 56% 57% 58% 64% 63% All Div'ds to Net Prof 63%
2015 2016 2017 28%; coal, 15%; wind, 8%; hydro, 8%; purchased, 41%. Fuel costs:
%Cha?e Retail Sales (KWH) +.6 -2.1 +3.9 BUSINESS: Portland General Electric Company (PGE) provides Avg. In ust. Use (MWH~ 17485 16146 16041 electricity to 875,000 customers in 52 cities in a 4,000-square-mile 30% of revenues. '17 reported depreciation rate: 3.6%. Has 2,900 Avg.lndust.Revs~ (I) 5.01 4.99 4.94 area of Oregon, including Portland and Salem. The company is in employees. Chairman: Jack E. Davis. President and Chief Execu-CapacityatPeak ~ 4609 4730 4743 the process of decommissioning the Trojan nuclear plant, which it tive Officer: Maria M. Pope. Incorporated: Oregon. Address: 121 Peak load, Summer! ) 3914 3726 3976 closed in 1993. Electric revenue breakdown: residenlial, 48%; com- S.W. Salmon Street, Portland, Oregon 97204. Telephone: 503-464-Annualloadfactor(Y,/ NA NA NA
%Change Customers yr-end) +1.2 +1.2 +1.3 mercial, 33%; industrial, 11 %; other, 8%. Generaling sources: gas, 8000. Internet: www.portlandgeneral.com.
F~ed Charge Cov. (%) 243 271 298 Portland General Electric has filed a Unrecovered costs associated with the rate case. The utility requested an in- Carty gas-fired plant continue to be a ANNUAL RATES Past Past Esl'd '15-'17 drag on earnings. The facility was com-of change (per sh) 10Yrs. 5Yrs. to '21-'23 crease of $89 million (4.8%), based on a re-Revenues -1.5% -2.0% 3.0% turn of 9.5% on a common-equity ratio of pleted in 2016, several months after PGE "Cash Flow" 1.5% 3.0% 5.5% 50%. An order from the Oregon Public declared the contractor of the project in Earnings
- 4.0% 3.5% 4.0% default of the construction agreement.
Dividends 9.0% 3.5% 6.0% Utility Commission (OPUC) is expected in Book Value 3.0% 3.5% 3.0% December, with new tariffs taking effect at However, $123 million of the plant's $637 the start of 2019. million cost are not reflected in rates. PGE Cal- QUARTERLY REVENUES ($ mill.) Full filed suit against the contractor's insurer, endar Mar.31 Jun.30 Sep.30 Dec.31 Year Earnings are likely to decline this year. Favorable weather patterns helped seeking to collect a $145.6 million perform-2015 473.0 450.0 476.0 499.0 1898.0 ance bond, plus damages. The company ex-2016 487.0 428.0 484.0 524.0 1923.0 the bottom line in 201 7, but the weather 2017 530.0 449.0 515.0 515.0 2009.0 in early 2018 turned the other way. In pects resolution of this matter to take two
. 2018 530 455 515 525 2025 fact, the Portland area had its second- . to four years, but was citing the same time 2019 555 470 530 545 2100 warmest January on record. We have frame two years ago. Unrecovered costs EARNINGS PER SHARE A lowered our earnings estimate by $0.20 a and litigation expenses reduced earnings Cal- Full endar Mar.31 Jun.JO Sep.30 Dec.31 Year share, to $2.20. Our revised estimate is by $0.09 a share in 2017, and the loss will 2.04 within PGE's guidance of $2.10-$2.25 a* widen to an estimated $0.12 a share this 2015 .62 .44 .40 .57 2016 .68 .42 .38 .68 2.16 share . year due to the lower tax shield from the 2017 .82 .36 .44 .67 2.29 There is a possible risk to earnings reduced federal tax rate.
2018 .70 .42 .43 .65 2.20 this year. PGE is going to ask the OPUC We forecast an earnings recovery in 2019 .75 .45 .45 .70 2.35 for permission to defer (for future 2019. We assume normal weather condi-QUARTERLY DIVIDENDS PAID 8
- t Full recovery) costs in 2018 associated with the tions and reasonable treatment in the Cal-endar Mar.31 Jun.30 Seo.JO Dec.31 Year upgraded customer information system the aforementioned rate case.
company expects to complete soon. If the This untimely stock has a dividend 2014 .275 .275 .28 .28 1.11 yield and 3- to 5-year total return 2015 .28 .28 .30 .30 1.16 OPUC doesn't approve this request and 2016 .30 .30 .32 .32 1.24 the utility must incur these costs, this potential that are about average for a would reduce earnings by $0.10 a share utility. ,
2017 .32 .32 .34 .34 1.32 2018 .34 .34 this year. Paul E. Debbas, CFA April 27. 2018 (A) Diluted EPS. Exel. nonrecurring losses: '13, Div'd reinvestment plan avail. t Shareholder in- 9.5%; earned on avg. com. eq., '17: 8.5%. , Company's Financial Strength* B++
42¢; '17, 19¢. '15 EPS don't sum due to round- veslment plan avail. (C) Incl. deferred charges. Regulatory Climate: Average. (F) '05 per-share Stock's Price Stability 95 ing. Next earnings report due late July. In '17: $4.92/sh. (D) In mill. (E) Rate base: Net data are pro forma, based on shs. oulstanding Price Growth Persistence 65 (B) Div'ds paid mid-Jan., Apr., July, and Oct.
- orig. cost. Rate allowed on com. eq. in '18: when stock began trading in '06. Earnings Predictability so***
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wtthout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part ~To s~bscribe call 1-800-VALUEL~EJ of tt may be reproduced, resold, stored or transmttted in any printed, electronic or other form, or used .for generating or marketing any printed or electronic publication, service or product:
L.J\,,,ll\,,,UUl\,,, I'.Ul'U - J 18-KCPE--480-RTS XCEL ENERGY NDQ-XEL I RECENT PRICE 45 ,61 IP/ERATIO 18 ,8 (Trailing: 19.7)
Median: 15.0 RE~_JIVE PIE RATIO 1,00 IDIV'YLDD 3.4o'o*/( 1.iu,,, ** 1 TIMELINESS 4 Lowered 3/23118 High: 25.0 22.9 21.9 24.4 27.8 29.9 31.8 37.6 38.3 45.4 52.2 48.4 *~ Target Price Range Low: 19.6 15.3 16.0 19.8 21.2 25.8 26.8 27.3 31.8 35.2 40.0 41.5 SAFETY TECHNICAL 8 50 1 00 1 Raised 5/1/15 5 Lowered 4/27/18 1--E-TA,.,-.*.,,..,.(.-..,...,=,..M.,.ark.,.e,.l)....,,....--1
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LEGENDS
, , , , Relative ~rice Strength
°~t~~~/:!a indicates recession t--t----t---+---t----t----tt---t::=::::--1--.;;m'tl--;;----tt--- +----t~--t----t'- 50 2021 2022 2023 00 60
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Price Gain An~~tJ~a 1---1---l---1---l---l--..,,e.l=-'~~----+.:irn:;::;;:pill!*ii t:'i:."::"'"1'.11'.!~11 '..::"1---l---*-l-*_::*.:.*:.:**:4:-"'.--l---l---l---l--30 High 50 (+10%) 6% ........ , ...,, .... ,, ' ... ., '* 25 Low 45 (Nil) 3% ,,, .... ,..... ..11*' .:;'.., .;;,,,.* ~ ' 20 Insider Decisions _. _.,. *, -* 15 J J A S O N D J F ****_ -.... ********* -.. ****** -** -.....*. 00 Ii to Buy O O O 1 0 0 0 0 0 "** " ** *.,. ***** " 10
- 10. * -
Options O O O O O O o O12 tos,n OO 1 0 0 1 1 0 0 1-------------+--+----+--+-------- ----------1 %TOT.RETURN3/18 - 7 ,5 Institutional Decisions I THIS VLARITH."
to Soll to Buy 2Q2017 294 242 Hld's(DD0) 416718 418292 379245 3Q2017 286 246 4Q2017 280 216 Percent shares traded 15 t 5
I I I -
- II ~ - - - i - - - < 1 yr.
3 yr.
5 yr.
STOCK 5.6 44.5 79.4 INDEX 9.7 24.3 68.8 l-:2=0"='02.,.,..,2=0=0=3T"2=0=0,...,.4-r-=20=0=5--2=oo=s,...,...,,2"'"00=7 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUELINEPUB.LLC 1-23 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 21.72 21.90 22.46 22.55 22.90 Revenues per sh 25.25 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 4.56 5.04 5.47 5.90 6.15 "Cash Flow" per sh 7.25
.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 2.10 2.21 2.30 2.45 2.55 Earnings per sh A 3.00 1.13 .75 .81 .85 .88 .91 .94 .97 1.00 1.03 1.07 1.11 1.20 1.28 1.36 1.44 1.52 1.60 Div'd Decl'd per sh e
- 1.90 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 7.26 6.42 6.54 8.25 7.95 Cap'I Spending per sh 6.75 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 20.89 21.73 22.56 23.55 24.85 Book Value per sh c 28.00 398.71 398.96 400.46 403.39 407.30 428.78 453.79 457.51 482.33 486.49 487.96 497.97 505.73 507.54 507.22 507.76 509.50 518.00 Common Shs Outst'g " 522.50 NIVI~ 11.6 13.6 15.4 14.8 16.7 13.7 12.7 14.1 14.2 14.8 15.0 15.4 16.5 18.5 20.2 Bold fig res are Avg Ann'I PIE Ratio 16.0 NMF .66 .72 .82 .80 .89 .82 .85 .90 .89 .94 .84 .81 .83 .97 1.02 Value Una Relative P/E Ratio .90 6.6% 5.2% 4.7% 4.6% 4.4% estln ates 4.0% 4.7% 5.1% 4.5% 4.2% 3.9% 3.9% 3.8% 3.7% 3.3% 3.1% Avg Ann'I Div'd Yield 4.0%
CAPITAL SlRUCTURE as of 12/31/17 11203 9644.3 10311 10655 10128 10915 11686 11024 11107 11404 11500 11850 Revenues ($mill) 13250 Total Debt $15791 mill. Due in 5 Yrs $4262 mill. 645.7
- 685.5 727.0 841.4 905.2 948.2 1021.3 1063.6 1123.4 1171.0 1240 1320 Net Profit ($mill) 1575 LT Debt $14520 mill. LT Interest $646 mill.
34.4% 35.1% 37.5% 35.8% 33.2% 33.8% 33.9% 35.8% 34.1% 30.7% 9.0% 9.0% Income Tax Rate 9.0%
Incl. $151 mill. capitalized leases.
(LT interest earned: 3.5x) 15.9%' 16.8%. 11.7% 9.4% 10.8% 13.4% 12.5% 7.7% 7.8% 9.4% 11.0% 10.0% AFUDC %to Net Profit 7.0%
52.2% 51.6% 53.1% 51.1% 53.3% 53.3% 53.0% 54.1% 56.3% 55.9% 58.0% 57.0% Long-Term Debt Ratio 58.0%
Leases, Uncapitalized Annual rentals $238 mill. 47.1% 47.7% 46.3% 48.9% 46.7% 46.7% 47.0% 45.9% 43.7% 44.1% 42.0% 43.0% Common Equity Ratio 42..0%
Pension Assets-12/17 $3088 mill. 14800 15277 17452 17331 19018 20477 21714 23092 25216 25975 28450 29775 Total Capital ($mill) 34800 Oblig $3828 mill.
Pfd Stock None 17689 18508 20663 22353 23809 26122 28757 31206 32842 34329 36775 39050 Net Plant ($mill) 42900 6.0% 6.2% 5.7% 6.5% 6.1% 6.0% 6.0% 5.8% 5.7% 5.8% 5.5% 5.5% Return on Total Cap'I 6.0%
Common Stock 508,064,983 shs. 9.1% 9.3% 8.9% 9.9% 10.2% 9.9% 10.0% 10.0% 10.2% 10.2% 10.5% 10.5% Return on 5hr. Equity 10.5%
as of 2/19/18 9.2% 9.4% 8.9% 9.9% 10.2% 9.9% 10.0% 10.0% 10.2% 10.2% 10.5% 10.5% Return on Com Equity E 10.5%
MARKET CAP: $23 billion (Large Cap) 3.8% 3.7% 3.6% 4.3% 4.7% 4.5% 4.5% 4.3% 4.0% 3.9% 4.0% 4.0% Retained to Com Eq 4.0%
ELEClRIC OPERATING STATISTICS 59% 61% 59% 56% 54% 54% 55% 57% 61% 62% 62% 62% All Div'ds to Net Prof 63%
2015 2016 20~~ +---B-US_I_N.... ES_S_:_X_c....
el-En-e-rg....y-l-nc-.-is.._th-e-p-a...re-n-t-of_._N_ort-h-er-n...S-ta-te_s_._m_i_ll.-e-le...ct-ric-,-1-.9...*m-i-ll.-g-as....-E-le-c.-r... ev-.-b-re-ak-d-ow_n_:-re-si-de-n-tia...l,-3-1_%_;-i
%Change Relail Sales (K'Ml) -.6 +.3 LargeC&IUse(Ml',ll)- 23521 22519 22642 Power, which supplies electricity to Minnesota, Wisconsin, North sm. comm'I & ind'I, 36%; lg. comm'I & ind'I, 18%; other, 15'/o. Gen-Large C&IRevs. per KWH(¢) 6.10 6.17 6.36 Dakota, South Dakota & Michigan & gas to Minnesota, Wisconsin, erating sources not available. Fuel costs: 40% qf revs. '17 reported Capacifya!Peak(Mwl NA NA NA North Dakota & Michigan; Public Service of Colorado, which sup- depr. rate: 3.1 %. Has 11,500 employees. Chairman, Pres. & CEO:
Peak Load, Summer (Mw)
Annual Load Factor(%)
19583 20423 195 NA NA Jl plies electricity & gas to Colorado; & Southwestern Public Service, Ben Fowke. Inc.: MN. Address: 414 Nicollet Mall, Minneapolis, MN
+.9 which supplies electricity to Texas & New Mexico. Customers: 3.6 55401. Tel.: 612-330-5500. Internet: www.xcelenergy.com.
%Change Customers ~r-en~ +.9 +.9 F~edChargeCov. (%) 358 342 330 1---------------------------
Xcel Energy is awaiting orders on rate 2019. Xcel's goal --------------
for long-term earnings
,_A_N_N_U~A~L-RA~TE-S--Pa_s_t--P-as-t-Es_t_'d-,- -.,--<
15 17 cases in three states. The largest *ones growth is 5%-6% annually. . .
ofchange(persh) 10Yrs. 5Yrs. to'21-'23 are Public Service of Colorado's multiyear Xcel's utilities have some proposals Revenues -1.0% .5% 2.5% electric and gas applications. The utility pending involving renewable energy.
"Cash Flow" 4.0% 6.0% 6.5% requested electric hikes totaling $245 mil- The aim is to retire coal-fired units and re-B!rci~~Js ~:~~ ~:~~ ~j~ lion from 2018 through 2020. and gas in- place them with renewab1es. gas, and Book Value 4.5% 4.5% 4.5% creases totaling $139 million over that storage - and to do this without raising Cal- QUARTERLYREVENUES($mill.) Full span. Each filing is based on a 10% return rates for customers. SPS received approval endar Mar.31 Jun.30 Sep.30 Dec.31 Year on a 55.25% common-equity ratio. An in- in New Mexico, and awaits a decision in 2015 2962 2515 2901 2646 11024 terim gas increase of $.63 million took ef- Texas, for a $1.6 billion project to add 2016 2772 2500 3040 2795 11107 feet at the start of 2018; and the company wind in the two states. P.S. of Colorado ex-2017 2946 2645 3017 2796 11404 is asking for a $75 million interim gas pects a ruling in July on its plan to spend 2018 2900 2650 3050 2900 11500 raise at the start of June. Southwestern up to $1.5 billion to add wind, solar, and 2019 3000 2700 3150 3000 11850 Public Service asked the regulators in gas.
Cal- EARNINGSPERSHAREA . Full Texas and New Mexico for a total of $97 The board of directors raised the com-endar Mar.31 Jun.30 Sep.30 Dec.31 Year million, based on a _10.25% return on a* mon dividend, effective with the April 1-::-:,..,,-=--+--_..,.,,.--_=-:,----:_,...,---:.4.,--+--=c-:.-::--1 2015 45 39 84 1 2 10 58% common-equity ratio. Rulings are ex- paYillent. The increase was $0.02 a share 2016 .47 .39 .90 .45 2.21 pected this summer in New Mexico and (5.6%) quarterly, the same as in recent 2017 .47 .45 .97 .42 2.30 early in the fourth quarter (retroactive to years. Xcel's goals for the dividend are 2018 .55 .45 1.00 .45 2.45 January of 2018) in Texas. growth of 5%-7% annually and a payout 2019 .58 .47 1.03 .47 2.55 Rate relief is boosting Xcel's earning ratio of 60%-70%.
t--C-al---+--Q-UA-R-TE-R-LY_D_IV_ID-EN-=D,.,.S.,,.PA'"'ID-B-.--i-F-ul--1I power and enabling the company to This untiDlely stock has a dividend endar Mar.31 Jun.30 Sec.30 Dec.31 Year reduce the gap between its earned yield and 3- to 5-year total return and allowed returns on equity. Man- potential that are about average, by m~
2014 2017
- 28
- ~~
.34
.3o
- ~~
.36
.3o j~
.36
.3o
- ~~
.36 u:
1.1 8 1.42 agement's earnings guidance for 2018 is
$2.37-$2.47 a share. Our estimate of $2.45 is near the upper end of this range. We utility standards. This might be accept-able for conservative accounts, given the issue's top rank for Safety..
2018 .36 .38 forecast more-modest profit growth in Paul E. Debbas, CFA April 27, 2018 (A) Diluted EPS. Exel. nonrecurring gain 1¢. '17 EPS don't sum due to rounding. Next tangibles. In '17: $5.92/sh. (D) In mill. (E) Rate Company's Financial Strength A+
(losses): '02, ($6.27); '10, 5¢; '15, (16¢); '17, earnings report due early May. (B) Div'ds his- base: Varies. Rate allowed on com. eq. Stock's Price Stability 100 (5¢); gains (losses) on discontinued ops.: '03, torically paid mid-Jan., Apr., July, and Oct. (blended): 9.6%; earned on avg. com. eq., '17: Price Growth Persistence 55 27¢; '04, (30¢); '05, 3¢; '06, 1¢; '09, (1¢); '10,
- Div'd reinvestmenl plan available. (C) Incl. in- 10.4%. Regulatory Climate: Average. Earnings Predictability 100,
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed lo be reliable and is provided wtthout warranties of any kind. i - , f THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part, I I I '
- 1*e:11Ilall!llll :Ill 1111- '.*
of It may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product'.
- Schedule AHG - 4 18-KCPE-480-RTS Alliant Enerl:I (LN!}
Date Hii:h Low Close 1/B/E/S Growth Estimates LNT 7/3/2017 $ 40.36 $ 39.54 $ 39.71 Current Qtr. 7.30%
7/10/2017 $ 40.21 $ 39.36 $ 39.97 Next Qtr. 9.30%
7/17/2017 $ 41.39 $ 39.81 $ 41.38 Current Year 9.80%
7/24/2017 $ 41.66 $ 40.31 $ 40.47 Next Year 6.10%
7/31/2017 $ 41.40 $ 40.31 $ 41.09 Next 5 Years (per annum) 5.85%
8/7/2017 $ 41.75 $ 41.03 $ 41.37 Past 5 Years (lier annuml 4.21%
8/14/2017 $ 42.32 $ 41.38 $ 42.24 Source: YahooFinance; July 18, 2018 8/21/2017 $ 43.09 $ 42.17 $ 42.87 8/28/2017 $ 43.23 $ 42.54 $ 42.57 9/4/2017 $ 43.24 $ 42.56 $ 43.19 9/11/2017 $ 43.69 $ 42.27 $ 42.90 9/18/2017 $ 42.91 $ 41.72 $ 41.73 Value-Line EPS DPS 9/25/2017 $ 42.32 $ 41.16 $ 41.57 Past 10 Years 5.00% 7.50%
10/2/2017 $ 42.14 $ 41.05 $ 41.92 Past 5 Years 6.50% 6.50%
10/9/2017 $ 43.46 $ 41.84 $ 43.05 Est '15-'17 to '21-'23 6.50% 6.00%
10/16/2017 $ 43.97 $ 42.78 $ 43.87 10/23/2017 $ 43.95 $ 42.72 $ 43.75 2017 2018 2019 '21 to '23 10/30/2017 $ 44.39 $ 42.88 $ 43.83, $ 1.26 $ 1.34 $ 1.42 $ 1.66 11/6/2017 $ 44.29 $ 43.51 $ 43.68 Source: June 15, 2018; Value-Line 11/13/2017 $ 45.55 $ 43.69 $ 44.40 11/20/2017 $ 44.49 $ 44.01 $ 44.22 11/27/2017 $ 45.38 $ 44.11 $ 44.83 NYSE:LNT Mean 12/4/2017 $ 45.22 $ 43.96 $ 44.94 LT Growth(%) 5.91 6.00 6.00 5.73 0.13 3 12/11/2017 $ 45.10 $ 43.56 $ 44.43 Source: SNL/S&P Global 12/18/2017 $ 44.37 $ 42.18 $ 42.50 12/25/2017 $ 42.97 $ 42.18 $ 42.61 --- - ------- -- ---- - - - - - - - - - ------
S.75 --- 6.75 1/1/2018 $ 42.72 1/8/2018 $ 41.58 1/15/2018 $ 40.17 40.92 39.49 39.33 41.08 39.53 39.41 l
6.50 6.50 1/22/2018 $ 40.54 $ 39.45 $ 40.30 1/29/2018 $ 40.18 $ 38.46 $ 38.91 2/5/2018 $ 39.34 $ 36.84 $ 38.42 G.25 \ 6.25 2/12/2018 $ 39.81 $ 37.89 $ 39.75 2/19/2018 $ 39.70 $ 38.01 $ 39.42 fe 2/26/2018 $ 39.82 $ 37.85 $ 38.22 Cl 6.00 ' 6.00 3/5/2018 $ 38.99 $ 37.91 $ 38.71 3/12/2018 $ 40.22 $ 38.75 $ 40.13 S.7S 5.75 3/19/2018 $ 40.58 $ 39.38 $ 39.45 3/26/2018 $ 41.04 $ 39.43 $ 40.86 4/2/2018 $ 41.45 $ 40.34 $ 41.02 5.50 liSO 4/9/2018 $ 41.36 $ 40.38 $ 41.11 4/16/2018 $ 42.30 $ 41.23 $ 41.54 I 4/23/2018 $ 43.13 $ 41.45 $ 43.06 :~.--- -.--~---, ,....._,
4/30/2018 $ 43.47 $ 42.04 $ 43.27 S.25
~ ~ ~ ~ -~ ~ ~ ~
~ ~ ~
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~ ~ ~ ~'b ..!tJ ~q;.
5.25 5/7/2018 $ 43.29 5/14/2018 $ 41.78 41.02 40.30 41.66 40.57
~ ./ <JI° ~.:I ,,~ ',, ',~# '~l~ 'i~
~ ~ ~
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.f 5/21/2018 $ 40.94 $ 40.11 $ 40.79 0,1~
5/28/2018 $ 41.81 $ 40.47 $ 40.63 6/4/2018 $ 40.76 $ 38.99 $ 39.23 - L T Growth - LT Growth 6/11/2018 $ 40.08 $ 38.22 $ 39.96 6/18/2018 $ 41.28 $ 39.86 $ 41.09 6/25/2018 $ 42.78 $ 41.07 $ 42.32 7/2/2018 $ 43.42 $ 42.15 $ 43.41 Mimmum $ 36.84 $ 38.22 Maximum $ 45.55 $ 44.94 Mean $ 41.56 Source: l'ahooFmance, July 18, 2018
Schedule AHG - 4 l 8-KCPE-480-RTS Allete, Inc. (ALE)
Date High Low Close 1/B/E/S Growth Estimates ALE 7/3/2017 $ 72.20 $ 70.55 $ 71.26 Current Qtr. 1.40%
7/10/2017 $ 71.67 $ 69.79 $ 70.29 Next Qtr. 11.10%
7/17/2017 $ 73.53 $ 69.90 $ 73.45 Current Year 6.90%
7/24/2017 $ 73.76 $ 71.69 $ 72.57 Next Year 7.90%
7/31/2017 $ 75.12 $ 72.31" $ 73.. 98 Next 5 Years (per annum) 6.00%
8/7/2017 $ 75.17 $. 73.08 $ 73.30 : Past 5 Years (per annum) 5.88%
8/14/2017 $ 75.26 $ 72.86 $ 75.07 Source: YahooFinance; July 18, 2018 8/21/2017 $ 77.02 $ 74.70 $ 76.81 8/28/2017 $ 77.73 $ 76.68 $ 77.52 9/4/2017 $ 79.27 $ 77.31 $ 79.14 9/11/2017 $ 79.61 $ 77.00 $ 78.41 9/18/2017 $ 78.35 $ 76.88 $ 76.91 Value-Line EPS DPS 9/25/2017 $ 78.16 $ 76.55 $ 77.29 Past 10 Years 1.50% 3.50%
10/2/2017 $ 78.85 $ 76.55 $ 78.31 Past 5 Years 5.50% 3.00%
10/9/2017 $ 79.69 $ 77.98 $ 78.38 Est '15-'17 to '21-'23 5.00% 4.50%
10/16/2017 $ 79.54 $ 77.58 $ 78.93 10/23/2017 $ 79.85* $ 77.89 $ 79.69 2017 2018 2019 '21 to '23 10/30/2017 $ 80.00 $ 76.76 $ 76.93 $ 2.14 $ 2.24 $
- 2.34 $ 2.70 11/6/2017 $ 77.74 $ 75.20 $ 76.34 Source: June 15, 2018; Value-Line 11/13/2017 $ 78.59 $. 76.02 $ 77.50 11/20/2017 $ 78.69 $ 77.03 $ 78.18 11/27/2017 $ 80.93 $ 77.52 $ 80.21 NYSE : ALE Mean 12/4/2017 $ 81.24 $ 78.19 $ 79.33 LT Growth (%) 6.60 6.00 7.80 6.00 0.85 12/11/2017 $ 79.50 $ 76.70 $ 77.90 Source: SNUS&P Global 12/18/2017 $ 78.53 $ 73.40 $ 73.45 12/25/2017 $ 74.97 $ 72.96 $ 74.36 -------------------------------------
7.50 I ----- 7.50 1/1/2018 $ 74.42 $ 72.53 $ 73.55 1/8/2018 $ 74.13 $ 72.14 $ 73.00 I I
1/15/2018 $ 74.04 $ 71.80 $ 71.98 1/22/2018 $ 73.97 $ 71.85 $ 72.84 7.00 7.00 1/29/2018 $ 72.63 $ 70.26 $ 70.42 2/5/2018 $ 70.64 $ 66.64 $ 69.89 2/12/2018 $ 69.97 $ 67.20 $ 69.34 2/19/2018 $
2/26/2018 $
69.98 70.06
$ 67.56
$ 67.88 69.98 68.58 t
~
!:;
6.50 8.50 3/5/2018 $ 68.72 $ 67.07 $ 68.08 3/12/2018 $ 71.20 $ 68.06 $ 71.07 3/19/2018 $ 72.61 $ 70.06 $ 70.12 3/26/2018 $ 72.80 $ 70.13 $ 72.25 6.00 6.00 4/2/2018 $ 72.66 $ 70.40 $ 71.72 4/9/2018 $ 72.65 $ 71.04 $ 71.67 4/16/2018 $ 74.78 $ 71.88 $ 73.10 4/23/2018 $ 77.44 $ 73.11 $ 77.08 5,'50 - - - - - ~ - - - --- 550 4/30/2018 $ 79.86 $ 75.72 $ 79.62 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
5/7/2018 $
5/14/2018 $
79 .40 77.50
$ 75.98
$ 73.76 77.78 74.49
//////~///~//////#
5/21/2018 $ 76.15 $ 74.28 $ 76.00 Dato 5/28/2018 $ 78.12 $ 75.53 $ 76.12 6/4/2018 $ 76.56 $ 72.78 $ 73.11 - LT Growth - LT Growth 6/11/2018 $ 73.28 $ 70.46 $ 73.11 6/18/2018 $ 76.65 $ 73.06 $ 76.31 6/25/2018 $ 78.62 $ 76.39 $ 77.41 7/2/2018 $ 79.50 $ 76.97 $ 79.45 M1rumwn $ 66.64 $ 68.08 Maximwn $ 81.24 $ 80.21 Mean $ 74.78 Source: YahooFmance, July 18, 2018
Schedule AHG- 4 18-KCPE-480-RTS Ameren Core. !AEEl Date Hi!lh Low Close 1/B/E/S Growth Estimates AEE 7/3/2017 $ 54.92 $ 53.54 $ 54.14 Current Qtr. -1.30%
7/10/2017 $ 54.63 $ 53.59 $ 54.43 Next Qtr. 2.40%
7/17/2017 $ 56.58 $ 54.18 $ 56.53 Current Year 7.40% .
7/24/2017 $ 56.67 $ 55.60 $ 56.16 Next Year 6.20%
7/31/2017 $ 57.65 $ 56.02 $ 57.50 Next 5 Years (per annum) 6.30%
8/7/2017 $ 58.75 $ 57.55 $ 57.95 Past 5 Years ( per annum l 7.79%
8/14/2017 $ 59.75 $ 57.91 $ 59.21 Source: YahooFinance; July 18, 2018 8/21/2017 $ 60.58 $ 59.06 $ 60.37 8/28/2017 $ 60.79 $ 59:56 $ 59.80 9/4/2017 $ 60.28 $ 59.31 $ 60.09 9/11/2017 $ 60.91 $ 58.59 $ 59.81 9/18/2017 $ 59.85 $ 58.34 $ 58.51 Value-Line EPS DPS 9/25/2017 $ 59.78 $ 57.56 $ 57.84 Past 10 Years -1.00% -4.00%
10/2/2017 $ 58.90 $ 57.67 $ 58.78 Past 5 Years 0.50% 2.00%
10/9/2017 $ 60.74 $ 58.80 $ 60.41 Est '15-'17 to '21-'23 7.50% 5.50%
10/16/2017 $ 61.74 $ 60.13 $ 61.56 10/23/2017 $ 61.96 $ 60.52 $ 61.80 2017 2018 2019 '21 to '23 10/30/2017 $ 62.83 $ 61.48 $ 62.19 $ 1.78 $ 1.85 $ 1.94 $ 2.35 11/6/2017 $ 63.15 $ 61.95 $ 62.48 Source: June 15, 2018; Value-Line 11/13/2017 $ 64.89 $ 62.54 $ 63.30 11/20/2017 $ 63.66 $ 62.62 $ 62.98 11/27/2017 $ 64.36 $ 62.96 $ 63.75 NYSE:AEE Mean 12/4/2017 $ 64.02 $ 62.06 $ 63.19 LT Growth(%) 6.57 6.62 7.10 6.00 0.45 3 12/11/2017 $ 63.71 $ 60.32 $ 60.94 Source: SNL/S&P Global 12/18/2017 $ 61.22 $ 58.29 $ 58.69 12/25/2017 $ 59.44 $ 58.28 $ 58.99 1/1/2018 $ 59.03 $ 57.23 $ 57.39 6.70 - -------- - - 6.70 1/8/2018 $ 58.09 $ 55.42 $ 55.52 1/15/2018 $ 55.94 $ 54.83 $ 55.16 6.60 B.60 1/22/2018 $ 57.09 $ 55.26 $ 56.92 1/29/2018 $ 56.74 $ *54.77 $ 54.89 2/5/2018 $ 55.72 $ 51.89 $ 55.42 B.5<J 6.50 2/12/2018. $ 56.85 $ 54.32 $ 56.32 2/19/2018 $ 56.39 $ 54.23 $ 56.35 I 2/26/2018 $ 56.46 3/5/2018 $ 55.32 53.47 53.08 54.03 53.99 a*
!:i 6.40 6.40 3/12/2018 $ 55.64 $ 53.88 $ 55.49 3/19/2018 $ 55.96 $ 53.91 $ 54.01 6.30 6.30 3/26/2018 $ 56.79 $ 54.10 $ 56.63 4/2/2018 $ 57.92 $ 56.15 $ 57.13 6.W 6.20
,~
4/9/2018 $ 57.55 $ 55.01 $ 55.51 4/16/2018 $ 57.49 $ 55.67 $ 56.27 4/23/2018 $ 58.72 $ 56.30 $ 58.60
- 'I, . #'., .,.....~,.,
6.10 -----~--- 6.10 4/30/2018 $ 59.18 5/7/2018 $ 58.98 57.65 58.44 58.90 58.54
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5/14/2018 $ 57.06 $ 55.72 $ 56.26 5/21/2018 $ 59.23 $ 55.80 $ 58.87 '
Date 5/28/2018 $ 59.79 $ 58.06 $ 58.11 6/4/2018 $ 58.59 $ 56.19 $ 56.69
- LT Growth - LTGruwth 6/11/2018 $ 57.02 $ 55.21 $ 56.97 6/18/2018 $ 58.82 $ 56.97 $ 58.68 6/25/2018 $ 61.25 $ 58.74 $ 60.85 Mm1mwn $ 51.89 $ 53.99 Maximum $ 64.89 $ 63.75 Mean $ 58.17 Source. 2an00FmaI1Ce, July 18, 2018
Schedule AHG - 4 18-KCPE-480-RTS American Electric Power (AEP)
Date High Low Close lffi/E/S Growth Estimates AEP 7/3/2017 $ 69.69 $ 68.47* $ 69.15 Current Qtr. 13.30%
7/10/2017 $ 69.53 $ 68.11 $ 68.17 Next Qtr. 6.40%
7/17/2017 $ 69.99 $ 68.12 $ 69.98 Current Year 5.40%
7/24/2017 $ 70.81 $ 68.59 $ 70.43 Next Year 6.20%
7/31/2017 $ 71.20 $ 70.03 $ 70.88 Next 5 Years (per annum) 5.79%
8/7/2017 $ 71.61 $ 70.37 $ 70.56 Past 5 Years (per annwn) 2.52%
8/14/2017 $ 72.63 $ 70.46 $ 72.16 Source: YahooFinance; July 18, 2018 8/21/2017 $ 73.77 $ 72.13 $ 73.57 8/28/2017 $ 74.29 $ 73.27 $ 73.54 9/4/2017 $ 74.37 $ 73.24 $ 74.19 9/11/2017 $ 74.59 $ 72.29 $ 73.03 9/18/2017 $ 73.11 $ 70.44 $ 70.57 Value-Line EPS DPS 9/25/2017 $ 71.21 $ 69.93 $ 70.24 Past 10 Years 3.00% 4.00%
10/2/2017 $ 71.63 $ 69.55 $ 71.53 Past 5 Years 5 .50% 4 .50%
10/9/2017 $ 73.91 $ 71.45 $ 73.16 Est '15-'17 to '21-'23 4.50% 5.00%
10/16/2017 ..$ 73.99 $ 72.52 $ 73.98 10/23/2017 $ 74.90 $ 72.53 $ 74.02 2017 2018 2019 '21 to '23 10/30/2017 .$ 74.92 $ 73.57 $ 74.08 $ 2.39 $ 2.51 $ 2.63 $ 3.05 11/6/2017 $ 75.84 $ 73.56 $ 74.78 Source: June 15, 2018; Value-Line 11/13/2017 $ 77.93 $ 74.70 $ 76.38 11/20/2017 $ 77.06 $ 76.02 $ 76.47 11/27/2017 $ 77.97 $ 76.45 $ 77.24 NYSE : AEP Mean 12/4/2017 $ 78.07 $ 75.86 $ 76.93 LT Growth(%) 5.92 6.00 6.00 5.76 0.11 8 12/1112017 $ 77.22 $ 75.77 $ 76.54 Source: SNL/S&P Global 12/18/2017 $ 76.91 $ 73.62 $ 73.65 12/25/2017 $ 74.00 $ 72.94 $ 73.57 ------ --~--~-- ------------------, 6.00 6.00 1/1/2018 $ 73.42 $ 70.31 $ 70.80 1/8/2018 $ 71.53 $ 67.23 $ 67.46 1/15/2018 $ 68.59 $ 67.11 $ 67.76 1/22/2018 $ 69.80 $ 68.04 $ 68.75 5.50 5.50 1/29/2018 $ 68.98 $ 67.52 $ 67.75 2/5/2018 $ 68.42 $ 63.32 $ 64.72 2/12/2018 $ 67.52 $ 64.19 $ 67.26 2/19/2018 $ 67.50 $ 65.43 2/26/2018 $ 67.76 $ 64.60
$ 67.37
$ 65.18 st 5.00 5.00 3/5/2018 $ 66.72 $ 64.65 $ 65.65 3/12/2018 $ 67.92 $ 65.57 $ 67.81 3/19/2018 $ 68.34 $ 66.25 $ 66.39 3/26/2018 $ 69.24 $ 66.56 $ 68.59 ~-f,IJ I 4/2/2018 .$ 69.42 $ 67.69 $ 68.53 4/9/2018 $ 69.14 $ 66.46 $ 67.34 4/16/2018 $ 69.67 $ 67.42 4/23/2018 $ 70. 98 $ 68.19 4/30/2018 $ 70.81 $ 68.52
$ 68.46
$ 70.55
$ 69.39 4.00 I-~-
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
4.00 5/7/2018 $ 69.45 $ 66.03 $ 67.16 '\~ff , / .,<*#' / . /. . .ii>
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5/14/2018 $ 67.40 $ 64.46 $ 64.93 5/21/2018 $ 67.40 $ 64.58 $ 67.22 O~tc 5/28/2018 $ 68.43 $ 66.43 $ 66.68 6/4/2018 $ 67.12 $ 63.67 $ 64.11 - LT Growth - LT Growth 6/11/2018 $ 65.13 $ 62.71 $ 65.05 6/18/2018 $ 67.82 $ 64.94 $ 67.35 6/25/2018 $ 70.30 $ 67.57 $ 69.25 7/2/2018 $ 71.16 $ 69.12 $ 71.13 Minimum S 62.11 $ 64.1-1 Maximwn $ 78.07 $ 77.24 Mean $ 70.22 Source: YaiiooFmance, July 18, 2018
Schedule AHG - 4 18-KCPE-480-RTS Consolidated Edison (ED}
Date Hii:h Low Close 1/B/E/S Growth Estimates ED 7/3/2017 $ 81.28 $ 80.04 $ 80.53 Current Qtr. -1.70%
7/10/2017 $ 81.22 $ 80.04 $ 80.73 Next Qtr. 0.70%
7/17/2017 $ 82.98 $ 80.49 $ 82.93 Current Year 3.60%
7/24/2017 $ 82.98 $ 81.24 $ 82.38 Next Year 4.20%
7/31/2017 $ 83.62 $ 82.15 $ 82.80 Next 5 Years (per annum) 3.39'Yo 8/7/2017 $ 84.16 $ 82.51 $ 82.87 Past 5 Years (iier annum l 2.66%
8/14/2017 $ 84.07 $ 82.04 $ 83.53 Source: YahooFinance; July 18, 2018 8/21/2017 $ 84.87 $ 83.31 $ 84.48 8/28/2017 $ 84.92 $ 83.76 $ 83.99 9/4/2017 $ 85.68 $ 83.82 $ 85.53 9/11/2017 $ 86.16 $ 83.44 $ 84.44 9/18/2017 $ 84.55 $ 81.58 $ , 81.59 Value-Line EPS DPS 9/25/2017 $ 82.35 $ 80.02 $ 80.68 Past 10 Years 2.50% 1.50%
10/2/2017 $ 81.93 $ 80.26 $ 81.56 Past 5 Years 2.00% 2.00%
10/9/2017 $ 84.09 $ 81.40 $ 83.08 Est '15-'17 to '21-'23 3.00% 3.50%
10/16/2017 $ 85.08 $ 82.28 $ 84.86 10/23/2017 $ 86.33 $ 84.24 $ 85.92 2017 2018 2019 '21 to '23 10/30/2017 $ 87.58 $ 85.27 $ 87.04 $ 2.76 $ 2.86 $ 2.96 $ 3.30 11/6/2017 $ 88.08 $ 86.12 $ 87.19 Source: June 15, 2018; Value-Line 11/13/2017 $ 89.58 $ 86.22 $ 86.53 11/20/2017 $ 87.25 $ 85.86 $ 86.90 11/27/2017 $ 89.57 $ .86.82 $ 88.82 NYSE:ED Mean 12/4/2017 $ 89.26 $ 87.30 $ 88.92 LT Growth (%) 3.18 3.53 4.00 2.00 0.85 3 12/11/2017 $ 89.70 $ 86.93 $ 88.24 Source: SNL/S&P Global 12/18/2017 $ 88.27 $ 84.35 $ 84.75 12/25/2017 $ 85.45 $ 84.18 $ 84.95 1/1/2018 $ 84.94 $ 81.03 $ 81.74 ,.511 *- - ------ --------- ------------ ,.50 1/8/2018 $ 82.91 $ 79.18 $ 79.49 1/15/2018 $ 79.86 $ 77.77 $ 78.27 1/22/2018 $ 80.61 $ 78.37 $ 80.40 1/29/2018 $ 80.65 $ 77.89 $ 77.96
,.oo 4.00 2/5/2018 $ 78.72 $ 74.57 $ 76.89 2/12/2018 $ 77.98 $ 75.66 $ 77.77 2/19/2018 $ 77.93 $ 75.46 $ 77.63 2/26/2018 $ 78.04 $ 73.73 $ 74.35 ie 3.50 3.50 3/5/2018 $ 76.34 $ 73.98 $ 75.24 Cl 3/12/2018 $ 77.58 $ 75.18 $ 77.45 ~
3/19/2018 $ 78.22 $ 75.4! $ 75.58 3/26/2018 $ 78.40 $ 75.62 $ 77.94 3.00 3.00 4/2/2018 $ 79.39 $ 76.67 $ 78.56 4/9/2018 $ 79.12 $ 76.07 $ 76.69 4/16/2018 $ 79.19 $ 76.95 $ 77.60 4/23/2018 $ 80.78 $ 77.40 $ 80.43 4/30/2018 $ 80.82 $ 78.01 $ 79.25 2.50 -- ------ - - - - - - - ------------------------ .2.00
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
5/7/2018 $ 79.39
- 5/14/2018 $ 77.18 5/21/2018 $ 76.39 74.88 73.35 73.38
$ 76.83
$ 73.97
$ 75.91 c;i~ .f,.;<t' ,,l'~ . /. . ~~
. f
.._<Y~ ...... $# ~~f. -s-$ 4".,, ~/~~ ~J~ ,/ / /
5/28/2018 $ 76.99 $ 75.22 $ 75.54 Dale 6/4/2018 $ 76.06 $ 72.01 $ 72.75 6/11/2018 $ 73.78 $ 71.12 $ 73.73 - L T Growth - LTGrcwtl\
6/18/2018 $ 75.98 $ 73.41 $ 75.76 6/25/2018 $ 78.91 $ 75.97 $ 77.98 7/2/2018 $ 78.99 $ 77.55 $ 78.99 M1mmum $ 71.12 $ 12.15 Maximum $ 89.70 $ 88.92 Mean $ 80.75 Source: YahooFmance, July 18, 2018
Schedule AHG- 4 18-KCPE-480-RTS Duke Enerl:l: (!!UK)
Date Hii:h Low Close 1/B/E/S Growth Estimates DUK 7/3/2017 $ 83.84 $ 82.72 $ 83.42 Current Qtr. 8.90%
7/10/2017 $ 84.27 $ 82.80 $ 83.84 Next Qtr. NIA 7/17/2017 $ 85.23 $ 83.60 $ 85.20 Current Year 3.70%
7/24/2017 $ 85.28 $ 83.60 $ 84.91 Next Year 4.40%
7/31/2017 $ 86.58 $ 84.65 $ 86.48 Next 5 Years (per annum) 4.22%
8/7/2017 $ 86.90 $ 85.16 $ 85.70 Past 5 Years (!!er annuml 1.33%
8/14/2017 $ 86.97 $ . 85.61 $ 86.38 Source: YahooFinance; July 18, 2018 8/21/2017 $ 87.55 $ 86.11 $ 87.23 8/28/2017 $ 87.95 $ 86.73 $ 87.09 9/4/2017 $ 88.03 $ 86.79 $ 87.78" 9/11/2017 $ 88.40 $ 86.53 $ 87.30 9/18/2017 $ 87.31 $ 84.22 $ 84.25 Value-Line EPS DPS 9/25/2017 $ 85.16 $ 83.40 $ 83.92 Past 10 Years 2.50% 10.00%
10/2/2017 $ 84.74 $ 83.52 $ 84.64 Past 5 Years 0.50% 2.50%
10/9/2017 $ 87.60 $ 84.69 $ 86.79 Est '15-'17 to '21-'23 5.50% 4.50%.
10/16/2017 $ 88.06 $ 86.42 $ 87.93 10/23/2017 $ 88.55 $ 86.71 $ 87.95 2017 2018 2019 '21 to '23 10/30/2017 $ 89.50 $ 87.56 $ 88.52 $ 3.49 $ 3.64 $ 3.80 $ 4.40 Il/6/2017 $ 89.74 $ 87.61 $ 88.89 Source: June 15, 2018; Value-Line I 1/13/2017 $ 91.80 $ 88.45 $ 88.52 Il/20/2017 $ 89.20 $ 88.29 $ 88.78 11/27/2017 $ 89.72 $ 88.19 $ 88.73 NYSE:DUK Mean 12/4/2017 $ 89.43 $ 87.45 $ 88.05 LT Growth (% l 4.21 4.50 5.00 .3.00 0.80 5 12/Il/2017 $ 88.39 $ 86.72 $ 87.84 Source: SNL/S&P Global 12/18/2017 $ 88.15 * $ 83.75 $ 84.17 12/25/2017 $ 84.58 $ 83.56 $ 84.11 4.75 - - - ---- ----- - - -- - - ------------~----- 4.75 1/1/2018 $ 84.42 $ 81.35 $ 81.94 1/8/2018 $ 82.31 $ 78.55 $ 78.90 1/15/2018 $, 79.27 $ 76.64 $ 76.82 4.50 4.50 1/22/2018 $ 79.22 $ *76.85 $ 78.83 1/29/2018 $ 78.65 $ 76.43 $ 76.53 2/5/2018 $ 77.59 $ 72.93 $ 76.10 4.25 4.25 2/12/2018 $ 77.30 $ 74:66 $ 76.70 2/19/2018 $ 77.30 $ 74.82 $ 77.22 'ie 4.00 4.00 2/26/2018 $ 79.63 $ 74.58 3/5/2018 $ 77.67 $ 74.87 75.35 76.13 Cl 3/12/2018 $ 77.73 $ 76.06 $ 77.59 3.75 3.75 3/19/2018 $ 77.87 $ 75.03 $ 75.17 3/26/2018 $ 77.91 $ 75.23 $ 77.47 -
4/2/2018 $ 78.90 $ 76.57 $ 78.16 3.50 3.50 4/9/2018 $ 79.05 $ 75.96 $ 76.67 4/16/2018 $ 79.42 $ 76.80 $ 77.68 I
4/23/2018 $ 80.75 $ 77.57 $ 80.50 3.25
~
(\
- \
,:0 ...... ~ ...... ,..'I> ~ .
3.25 4/30/2018 $ 80.85 $ 78.82 5/7/2018 $ 80.13 $ 76.88 79.88 77.91 ~ ~ ...-t'-~' ~~
....... . s-"~ ~""' .;,.<f' ~....#""' . <ii~
(;'
,JP-it'*
j,'"' .f'(f' 4' /'"' -l 5/14/2018 $ 78.22 $ 73.13 $ 73.80 5/21/2018 $ 76.02 $ 73.35 $ 75.81 O~t, 5/28/2018 $ 77.57 $ 75.49 $ 76.08 6/4/2018 $ 76.50 $ 72.83 $ 73.12 - LT Growth - LT Growth 6/11/2018 $ 74.40 $ 71.96 $ 74.30 6/18/2018 $ 77.67 $ 74.04 $ 77.43 6/25/2018 $ 80.15 $ 77.47 $ 79.08 7/2/2018 $ 80.62 $ 78.90 $ 80.61 Mm1mum $ /1.96 $ /3.12 Maximum $ 91.80 $ 88.89 Mean $ 81.78 Source: YahooFmance, July 18, 2018
Schedule AHG - 4 18-KCPE-480-RTS Edison International {EIX)
Date High Low Close 1/B/E/S Growth Estimates EIX 7/3/2017 $ 78.46 $ 76.44 $ 76.83 Current Qtr. 8.20%
7/10/2017 $ 78.47 $ 76.38 $ 77.45 Next Qtr. -9.10%
7/17/2017 $ 79.01 $ 77.32 $ 78.98 Current Year . -8.90%
7/24/2017 $ 79.35 $ 78.08 $ 78.25 Next Year 10.20%
7/31/2017 $ 79.44 $ 77.75 $ 79.29 Next 5 Years (per annum) 3.19%
8/7/2017 $ 80.26 $ 78.94 $ 79.53 Past 5 Years (per armum) 2.53%
8/14/2017 $ 81.33 $ 78.70 $ 78.94 Source: YahooFinance; July 18, 2018 8/21/2017 $ 81.26 $ 78.91 $ 80.75 8/28i2017 $ 81.32 $ 79.54 $ 79.96 9/4/2017 $ 80.78 $ 79.40 $ 80.74 9/11/2017 $ 81.58 $ 80.34 $ 81.20 9/18/2017 $ 81.41 $ 78.22 $ 78.28 Value-Line EPS DPS 9/25/2017 $ 79.45 $ 76.93 $ 77.17 Pas( IO Years 2.50% 6.00%
10/2/2017 $ 77.88 $ 76.55 $ 77.62 Past 5 Years 2.50% 9.00%
10/9/2017 $ 79.88 $ 77.39 $ 77.99 Est '15-'17 to '21-'23 4.50% 8.00%
10/16/2017 $ 79.83 $ 76.93 $ 79.60 I0/23/2017 $ 80.20 $ 78.55 $ 79.47 2017 2018 2019 '21 to '23 10/30/2017 $ 80.64 $ 78.63 $ 79.52 $ 2.23 $ 2.45 $ 2.57 $ 3. IO 11/6/2017 $ 80.43 $ 78.68 $ 80.06 Source: June 15, 2018; Value-Line 11/13/2017 $ 83.38 $ 80.16 $ 80.89 11/20/2017 $ 81.14 $ 79.72 $ 80.55 11/27/2017 $ 81.96 $ 80.34 $ 80.76 NYSE : EIX Mean 12/4/2017 $ 81.19 $ 67.80 $ 71.80 LT Growth(%) 4.10 3.93 7.00 2.48 1.55 5 12/11/2017 $ 73.23 $ 67.28 $ 69.71 Source: SNL/S&P'Global 12/18/2017 $ 71.11 $ 62.67 $ 65.23 12/25/2017 $ 65.30 $ 63.19 $ 63.24 7.00 i -----~------------- 7,00 1/1/2018 $ 63.73 $ 62.03 $ 62.98 1/8/2018 $ 64.34 $ 61.25 $ 61.42 1/15/2018 $ 62.64 $ 60.64 $ 62.12 1/22/2018 $ 62.84 $ 61.52 $ 62.46 6.00 6.00 1/29/2018 $ 67.56 $ 61.16 $ 61.60 2/5/2018 $ 61.96 $ 57.63 $ 58.94 2/12/2018 $ 61.37 $ 58.69 $ 61.05 2/19/2018 $ 62.56 $ 58.87 $ 62.17 i
~ 5.00 5.00 2/26/2018 $ 62.62 $ 59.04 $ 59.59
!:;
3/5/2018 $ 60.84 $ 58.80 $ 59.38 3/12/2018 $ 65.15 $ 59.12 $ 65.15 3/19/201.8 $ 65.27 $ 61.77 $ 62.16 4.00 4.00 3/26/2018 $ 63.78 $ 61.47 $ 63.66 4/2/2018 $ 64.11 $ 62.09 $ 63.38 4/9/2018 $ 63.86 $ 62.60 $ 63.44 4/16/2018 $ 65.82 4/23/2018 $ 66.60 63.30 63.73
$ 64.12
$ 65.79
,------- .---- ___.J 3.00 4/30/2018 $ 66.10 $ 62.54 $ 63.69 5/7/2018 $ 63.74 $ 60.23 $ 62.29 5/14/2018 $ 62.51 $ 60.49 $ 61.25 5/21/2018 $ 63.37 $ 60.87 $ 62.98 5/28/2018 $ 62.95 $ 60.53 $ 60.84 6/4/2018 $ 61.61 $ '58.80 $ 59.61 - LT Growth - LT Growth 6/11/2018 $ 60.54 $ 58.60 $ 60.44 6/18/2018 $ 61.78 $ 60.04 $ 61.70 6/25/2018 $ 63.72 $ 61.60 $ 63.27 7/2/2018 $ 65.30 $ 62.86 $ 65.28 Mirumum $ 5).63 $ 58.94 Maximum $ 83.38 $ 81.20 Mean $ 69.71 Source: I' ahooFmance, July 18, 2018
Schedule AHG - 4 18-KCPE-480-RTS El Paso Electric (EE}
Date Hii:h Low Close 1/B/E/S Growth Estimates EE 7/3/2017 $ 51.90 $ --50.30 $ 51.05 Current Qtr. -1.10%
7/10/2017 $ 51.30 $ 50.25 $ 51.05 Next Qtr. 10.20%
7/17/2017 $ 53.35 $ 50.85 $ 53.00 Current Year 5.00%
7/24/2017 $ 53.10 $ 51.45 $ 51.65 Next Year 5.10%
7/31/2017 $ 53.73 $ 51.55 $ 53.35 Next 5 Years (per annum) 5.20%
8/7/2017 $ 54.03 $ 52.83 $ 53.45 Past 5 Years (Iler annum} 14.71%
8/14/2017 $ 54.25 $ 53.00 $ 53.95 Source: Y ahooFinance; July 18, 2018 8/21/2017 $ 55.60 $ 5l65 $ 55.35 8/28/2017 $ 55.85 $ 54.85 $ 55.40 9/4/2017 $ 55.95 $ 54.95 $ 55.95 9/11/2017 $ 56.58 $ 54.35 $ 55.15 9/18/2017 $ 55.40 $ 54.30 $ 54.65 Value-Line EPS DPS 9/25/2017 $ 55.75 $ 54.58 $ 55.25 Past 10 Years 6.50%
10/2/2017 $ 57.00 $ 55.30 $ 56.85 Past_ 5 Years 18.00%
10/9/2017 $ 58.70 $ 56.85 $ 58.10 Est '15-'17 to '21-'23 4.50% 7.00%
10/16/2017 $ 58.05 $ 56.00 $ 57.25 10/23/2017 $ 58.70 $ 56.75 $ 58.40 2017 2018 2019 '21 to '23 10/30/2017 $ 58.45 $ 55.45 $ 57.60 $. 1.32 $ 1.42 $ 1.52 $ 1.85 11/6/2017 $ 58.65 $ 57.25 $ 57.75 Source: Jnne 15, 2018; Value-Line 11/13/2017 $ 60.70 $ 57.50 $ 60.20 11/20/2017 $ 60.70 $ 59.15 $ 59.65 11/27/2017 $ 61.15 $ 59.30 $ 60.25 NYSE:EE Mean 12/4/2017 $ 61.10 $ 58.55 $ 58.90 LT Growth(%) 5.10 5.10 5.20 5.00 0.10 2 12/11/2017 $ 59.40 $ 57.98 $ 59.10 Source: SNL/S&P Global 12/18/2017 $ 59.45 $ 54.75 $ 55.15 12/25/2017 $ 55.60 $ 54.60 $ 55.35 1/1/2018 $ 55.75 $ 53.65 $ 54.25 S.00 8.00 1/8/2018 $ 55.10 $ 50.70 $ 51.05 1/15/2018 $ 52.15 $ 50.70 $ 51.65 1/22/2018 $ 52.30 $ 51.15 $ 51.60 1/29/2018 $ 52.38 $ 50.95 $ 5_1.05 7.00 7_oo 2/5/2018 $ 51.45 $ 48.15 $ 50.75 2/12/2018 $ 51.45 $ 49.70 $ 51.30 2/19/2018 $ 51.40 $ 49.65 $ 50.55 ie 2/26/2018 $ 51.35 $ 48.05 $ 48.60 ~ 6.00 6.00 3/5/2018 $ 49.60 $ 48.05 $ 48.50 I-3/12/2018 $ 49.60 $ 48.25 $ 49.60 3/19/2018 $ 50.70 $ 48.85 $ 48.85 3/26/2018 $ 51.25 $ 48.80 $ 51.00 6.00 5.00 4/2/2018 $ 51.30 $ 49.60 $ 50.35 4/9/2018 $ 50.50 $ 48.50 $ 48.90 4/16/2018 $ 50.40 $ 48.90 $ 49.05 IL_____
4/23/2018 $ 51.55 $ 49.05 $ 51.35 ,.oo ,.oo 4/30/2018 $ 56.90 $ 49.45 $ 55.05 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
5/7/2018 $ 56.65 5/14/2018 $ 56.80
$ 54.50
$ 54.33 56.55 55.40 / / / / / / / / / / / / / ~ / / / ~"'"' (fi' 5/21/2018 $ 58.25 $ 55.20 $ 58.05 Dato 5/28/2018 $ 59.13 $ 57.65 $ 58.60 6/4/2018 $ 59.15 $. 55.60 $ 55.95 - LT Growth - LTGruwth 6/11/2018 $ 56.20 $ 54.75 $ 55.70 6/18/2018 $ 58.85 $ 55.80 $ 58.80 6/25/2018 $ 59.35 $ 57.70 $ 59.10 7/2/2018 $ 60.10 $ 58.25 $ 60.05 Mm1mum $ 48.05 $ 48.50 Maximum $ 61.15 $ 60.25 Mean $ 54.44 Source: l'ahooFmance, July 18, 2018
Schedule AHG - 4 18-KCPE-480-RTS IDACORP, Inc (IDA}
Date Hir;h Low Close 1/B/E/S Growth Estimates IDA 7/3/2017 $ 85.73 $ 83.75 $ 84.64 Current Qtr. 4.00%
7/10/2017 $ 85.15 $ 83.46 $ 84.07 Next Qtr. -3.90%
7/17/2017 $ 87.90 $ 83.60 $ 87.84 ClllTent Year 0.20%
7/24/2017 $ 87.83 $ 85.59 $ 86.00 Next Year 3.60%
7/31/2017 $ 87.63 $ 85.31 $ 86.56 Next 5 Years (per annum) 3.55%
8/7/2017 $ 88.23 $ 86.23 $ 86.78 Past 5 Years (Iler annuml 2.88%
8/14/2017 $ 87.90 $ 86.26 $ 87.15 Source: YahooFinance; July 18, 2018 8/21/2017 $ 89.75 $ 86.44 $ 89.54 8/28/2017 $ 89.94 $ 88.36 $ 89.32 9/4/2017 $ 91.60 $ 89.17 $ 91.40 9/11/2017 $ 91.98 $ 89.05 $ 90.06 9/18/2017 $ 90.06 $ 87.74 $ 87.75 Value-Line EPS DPS 9/25/2017 $ 89.06 $ 87.61 $ 87.93 Past 10 Years 7.50% 5.50%
10/2/2017 $ 89.25 $ 87.55 $ 88.44 Past 5 Years 4.50% 10.50%
10/9/2017 $ 91.61 $ 88.18 $ 90.34 Est '15-'17 to '21-'23 3.50% 6.50%
10/16/2017 $ 92.26 $ 89.79 $ 91.68 10/23/2017 $ 93.22 $ 90.10 $ 93.18 2017 2018 2019 '21 to '23 10/30/2017 $ 93.79 $ 91.06 $ 92.71 $ 2.24 $ 2.40 $ 2.56 $ 3.05 11/6/2017 $ 95.57 $ 92.50 $ 95.17 Source: June is, 2018; Value-Line 11/13/2017 $ 98.43 $ 95.08 $ 97.23 11/20/2017 $ 97.98 $ 96.20 $ 96.55 11/27/2017 $ 100.04 $ 96.19 $ 98.23 NYSE:IDA Mean 12/4/2017 $ 99.03 $ 95.95 $ 97.16 LT Growth(%) 3.91 4.00 5.00 2.74 0.93 3 12/11/2017 $ 97.26 $ 93.92 $ 95.51 Source: SNL/S&P Global 12/18/2017 $ 96.13 $ 90.03 $ 90.66 12/25/2017 $ 92.43 $ 89.81 $ 91.36 --------~
5.25 - 5.25 1/1/2018 $ 91.40 $ 87.23 $ 87.69 1/8/2018 $ 88.31 $ 82.08 $ 83.32 1/15/2018 $ 84.70 $ 82.62 $ 83.86 5.00 5.00 1/22/2018 $ 86.74 $ 83.10 $ 86.07 1/29/2018 $ 86.57 $ 83.25 $ 83.39 2/5/2018 $ 84.32 $ 79.59 $ 83.57 4.75 4.75 2/12/2018 $ 85.53 $ 82.02 $ 85.27 2/19/2018 $ 85.05 $ 82.23 $ 84.98 ,:.
!::j 2/26/2018 $ 85.25 $ 80.45 3/5/2018 $ 83.00 $ 80.29 81.61 81.95 I
t.:J ,1_5(1 ,.so Gl 0
~
I-3/12/2018 $ 86.22 $ 81.54 $ 86.10 ..J !ii' 3/19/2018 $ 87.95 $ 84.25 $ 84.34 3/26/2018 $ 88.60 $ 84.45 $ 88.27 4.25 4.25 4/2/2018 $ 88.77 $ 85.55 $ 87.25 4/9/2018 $ 87.86 $ 84.82 $ 85.74 4/16/2018 $ 89.83 $ 85.85 $ 89.08 *.oo *.00 4/23/2018 $ 94.16 $ 89.23 $ 93.63 4/30/2018 $ 96.01 $ 91.84 $ 94.04 5/7/2018 $ 94.34 $ 90.08 $ 91.24 3.75 --
-, - - - - - - - , - - - 3.75 5/14/2018 $ 91.71 $ 87.34 $ 87.90 B/,112017 1211812017 1/lll201S 1/29/21118 2127/201& ,1/211/2018 S/"12.018 ij/21/2ll1B 5/21/2!)18 $ 91.23 $ 87.66 $ 90.58 0dtt!
5/28/2018 $ 93.56 $ 87.03 $ 91.51 6/4/2018 $ 91.43 $ 86.28 $ 87.01 - LT Growth - LT Growth 6/11/2018 $ 88.56 "$ 85.23 $ 88.34 6/18/2018 $ 91.63 $ 88.28 $ 91.26 6/25/2018 $ 93.28 $ 91.40 $ 92.24 7/2/2018 $ 93.95 $ 91.79 $ 93.90 Mm1mum $ 19.59 $ 81.61 Maximum $ 100.04 $ 98.23 Mean $ 89.08 Source: YahooFmance, July 18, 2018
Schedule AHG - 4 18-KCPE-480-RTS Northwestern Core. (!ill:'.E}
Date Hii:h Low Close lffi/E/S Growth Estimates NWE 7/3/2017 $ 61.58 $ 59.85 $ 60.30 Current Qtr. NIA 7/10/2017 $ 60.75 $ 59.09 $ 59.68 Next Qtr. -1.40%
7/17/2017 $ 61.80 $ 58.99 $ 61.77 Current Year 3.60%
7/24/2017 $ 61.14 $ 58.42 $ 58.54 Next Year -0.30%
7/31/2017 $ 60.36 $ 57.58 $ 60.28 Next 5 Years (per annum) 3.16% 0.0241 8/7/2017 $ 61.36 $ 59.77 $ 60.18 Past 5 Years (Iler annwn} 11.96%
8/14/2017 $ 60.70 $ 58.63 $ 59.24 Source: YahooFinance; July 18, 2018 8/21/2017 $ 60.97 $ 59.16 $ 60.78 8/28/2017 $ 60.97 $ 59.78 $ 60.23
- 9/4/2017 $ 60.52 $ 59.56 $ 60.24 9/11/2017 $ 60.82 $ 58.21 $ 58.96 9/18/2017 $ 59.06 $ 57.74 $ 57.75 Vaine-Line EPS DPS 9/25/2017 $ 58.23 $ 56.87 $ 56.94 Past 10 Years 8.00% 5.50%
10/2/2017 $ 57.98 $ 56.44 $ 57.37 Past 5 Years 7.00% 7.00%
10/9/2017 $ 59.04 $ 57.29 $ 58.44 Est '15-'17 to '21-'23 3.50% 4.50%
10/16/2017 $ 59.41 $ 58.24 $ 58.70 10/23/2017 $ 59.46 $ 57.50 $ 59.22 2017 2018 2019 '21 to '23 10/30/2017 $ 59.97 $ 58.46 $ 59.78 $ 2.10 $ 2.20 $ 2.30 $ 2.60 11/6/2017 $ 61.17 $ 59.28 $ 60.34 Source: June 15, 2018; Value-Line 11/13/2017 $ 62.12 $ 60.11 $ 61.60 11/20/2017 $ 62.28 $ 61.32 $ 62.22 11/27/2017 $ 64.38 $ 62.02 $ 63.76 NYSE:NWE Mean 12/4/2017 $ 64.47 $ 62.46 $ 63.28 LT Growth(%) 3.01 3.01 3.02 3.00 0.01 2
- 12/11/2017 $ 63.33 $ 60.82 $ 61.60 Source: SNL/S&P Global 12/18/2017 $ 62.13 $ 58.48 $ 59.27 12/25/2017 $ 59.91 $ 58.66 $ 59.70 l.50 3.5()
1/1/2018 $ 59.82 $ 57.00 $ 57.41 1/8/2018 $ 57.80 $ 55.33 $ 55.40 1/15/2018 $ 55.50 $ 53.01 $ 53.21 1 1/22/2018 $ 54.75 $ 53.13 $
54.36 l.00 I 3.00 1/29/2018 $ 54.51 $ 52.71 52.86
.2/5/2018 $ 53.35 $ 50.01 $ 52.13 2/12/2018 $ 52.61 $ 50.64 2/19/2018 $ 52.50 $ 50.89 52.27 52.50
.c
- 2.5D
'i I 2.51l 2/26/2018 $ 52.76 $ 50.54 $ 51.06 e I
,_Cl I 3/5/2018 $ 52.13 $ 50.46 $ 51.07 .... 2.00 I 2.00 3/12/2018 $ 52.07 $ 50.65 $ 51.90 I 3/19/2018 $ 53.31 $ 51.47 $ 51.52 I
3/26/2018 $ 54.19 $ 51.63 $ 53.80 4/2/2018 $ 54.51 $ 52.43 4/9/2018 $ 54.33 $ 52.74 53.89 53.27 1.51l I 1.51) 4/16/2018 $ 55.20 $ 53.45 $ 53.85 4/23/2018 $ 55.65 $ 53.72 $ 55.36 1.00 _ . r -I 1.00 4/30/2018 $ 55.80 $ 54.15 $ 55.53 ~ . ._q,
~::, ~ ~
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,...q, ~
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5/7/2018 $ 55.67 $ 52.95 $ 53.72
'l'tf 'I~
..._,<f'
,l'~ .._.g;ref' *....$ ...~ / ,P,# re"fY"' J6' 5/14/2018 $ 53.99 $ 52.77 $ 53.21 5/21/2018 $ 54.63 $ 52.88 $ 54.49 Oat@
5/28/2018 $ 55.10 $ 52.98 $ 53.00 6/4/2018 $ 53.89 $ 51.53 $ 52.01 --LT Growth - LT Growth 6/11/2018 $ 54.33 $ 51.53 $ 54.25 6/18/2018 $ 56.81 $ 54.16 $ 56.70 6/25/2018 $ 57.74 $ 56.64 $ 57.25 7/2/2018 $ 58.65 $ 56.84 $ 58.63 M1mmwn $ 50.01 $ 51.06 Maximwn $ 64.47 $ 63.76 Mean $ 56.88 Source: l'ahooFmance, July 18, 2018
Schedule AHG- 4 18-KCPE-480-RTS OGE Enerl:;l: (OGE}
Date Hii:h Low Close 1/B/E/S Growth Estimates OGE 7/3/2017 $ 35.01 $ 34.09 $ 34.22 Current Qtr. -1.90%
7/10/2017 $ 34.90 $ 33.95 $ 34.57 Next Qtr. -6.50%
7/17/2017 $ 35.42 $ 34.26 $ 35.42 Current Year 4.70%
7/24/2017 $ 35.92 $ 35.33 $ 35.80 Next Year 4.50%
7/31/2017 $ 36.14 $ 35.35 $ 35.91 Next 5 Years (per annum) 4.30%
8/7/2017 $ 36.40 $ 35.27 $ 35.42 Past 5 Years (iier annum} 0.60%
8/14/2017 $ 35.75 $ 35.25 $ 35.59 Source: YahooFinance; July 18, 2018 8/21/2017 $ 36.36 $ 35.53 $ 36.22 8/28/2017 $ 36.51 $ 35.67 $ 35.76 9/4/2017 $ 36.21 $ 35.55 $ 36.15 9/11/2017 $ 36.67 $ 35.77 $ 36.31 9/18/2017 $ 36.41 $ 35.69 $ 35.84 Value-Line EPS DPS 9/25/2017 $ 36.39 $ 35.70 $ 36.03 Past 10 Years 4.5% 5.5%
10/2/2017 $ 36.36 $ 35.00 $ 35.58 Past 5 Years 1.0% 8.5%
10/9/2017 $ 37.30 $ 35.65 $ 36.82 Est '15-'17 to '21-'23 6.0% 8.0%
10/16/2017 $ 37.21 $ 36.62 $ 37.09 10/23/2017 $ 37.32 $ 36.35 $ 37.08 2017 2018 2019 '21 to '23 10/30/2017 $ 37.20 $ 35.60 $ 35.63 $ 1.27 $ 1.40 $ 1.54 $ 1.85 11/6/2017 $ 36.00 $ 34.93 $ 35.01 Source: June 15, 2018; Value-Line 11/13/2017 $ 36.01 $ 34.89 $ 35.20 11/20/2017 $ 35.27 $ 34.72 $ 34.90 11/27/2017 $ 36.00 $ 34.81 $ 35.23 NYSE:OGE Mean 12/4/2017 $ 35.67 $ 33.97 $ 34.46 LT Growth (%) 4.10 4.10 4.30 3.90 0.20 2 12/11/2017 $ 34.72 $ 33.47 $ 34.15 Source: SNL/S&P Global 12/18/2017 $ 34.40 $ 32.65 $ 33.01 12/25/2017 $ 33.20 $ 32.60 $ 32.91 1/1/2018 $ 33.07 $ 32.47 $ 32.50 7.0D - ----*---*--- - - - - - - - - - - - - - 7_00 1/8/2018 $ 32.84 $ 30.70 $ 30.74 1/15/2018 $ 31.78 $ 30.76 $ 31.42 1/22/2018 $ 32.54 $ 31.47 $ 32.14 1/29/2018 $ 32.36 $ 31.31 $ 31.35 6.00 6.00 2/5/2018 $ 31.54 $ 29.59 $ 30.39 2/12/2018 $ 31.66 $ 30.34 $ 31.56 2/19/2018 $ 33.06 $ 30.74 $ 32.95 "§:
2/26/2018 $ 33.00 $ 30.85 $ 31.19 e Cl 5.0D 5.00 3/5/2018 $ 32.08 $ 30.76 $ 31.35 !:;
3/12/2018 $ 32.17 $ 31.14 $ 32.00 3/19/2018 $ 32.39 $ 31.38 $ 31.43 3/.26/2018 $ 32.83 $ 31.43 $ 32.77 *. 00 ,.oo 4/2/2018 $ 32.98 $ 31.94 $ 32.37 4/9/2018 $ 32.31 $ 31.49 $ 31.61 4/16/2018 $ 32.91 $ 31.69 $ 32.47 4/23/2018 $ 33.16 4/30/2018 $ 34.37 32.38 32.70
$ 32.91
$ 34.17 l.00
~ ~ ~
~ ~
~ ~
~ ~
~ ~
~ ~ ~
3.00
~ ~
5/7/2018 $ 34.59 $ 33.46 $ 34.23
....~
ti' #<f- .;,"~ .,,/ ,._I' ,.l~ .}# ...~# ,i\"'1' ~.# $~ . ~'6'
. /' a.I' -;}~ ~"~
5/14/2018 $ 34.30 $ 33.22 $ 33.35 5/21/2018 $ 34.49 $ 33.29 $ 34.39 Dato 5/28/2,018 $ 35.42 $ 34.17 $ 3(38 6/4/2018 $ 34.81 $ 33.48 $ 33.75 - LT Growth - LT Growth 6/11/2018 $ 34.61 $ 33.19 $ 34.22 -J 6/18/2018 $ 35.08 $ 34.11 $ 34.96 6/25/2018 $ 35.54 $ 34.77 $ 35.21 7/2/2018 $ 35.39 $ 34.94 $ 35.28 M1mmum $ 29.59 $ 30.39 Maximum $ 37.32 $ 37.09 Mean $ 34.06 Source: 'i'ahooFmance, July 18, 2018
Schedule AHG - 4 18-K.CPE-480-RTS Pinnacle West ~NW}
Date Hii:h Low Close 1/B/E/S Growth Estimates PNW 7/3/2017 $ 85.87 $ 84.14 $ 84.67 Current Qtr. NIA 7/10/2017 $ 85.68 $ 83.95 $ 85.13 Next Qtr. 8.50%
7/17/2017 $ 87.25 $ 84.95 $ 87.23 Current Year 2.80%
7/24/2017 $ 87.38 $ 85.75 $ 86.14 Next Year 5.80%
7/31/2017 $ 88.95 $ 85.35 $ 88.06 Next 5 Years (per annum) 3.78%
8/7/2017 $ 89.11 $ 87.95 $ 88.53 Past 5 Years (iier annum l -8.83%
8/14/2017 $ 89.91 $ 88.41 $ 89.29 Source: YahooFinance; July 18, 2018 8/21/2017 $ 90.41 $ 88.63 $ 90.02 8/28/2017 $ 90.87 $ 89.46 $ 89.86 9/4/2017 $ 90.16 $ 88.94 $ 90.01 9/11/2017 $ 90.92 $ 87.79 $ 89.27 9/18/2017 $ 89.29 $ 86.14 $ 86.15 Value-Line EPS DPS 9/25/2017 $ 87.17 $ 83.95 $ 84.56 Past 10 Years 4.00% 2.50%
10/2/2017 $ 85.89 $ 84.14 $ 85.33 Past 5 Years 5.00% 2.50%
10/9/2017 $ 88.04 $ 85.17 $ 87.38 Est '15-'17 to '21-'23 5.00% 5.50%.
10/16/2017 $ 88.84 $ 86.79 $ 88.78 10/23/2017 $ 89.22 $ 87.04 $ 88.91 2017 2018 2019 '21 to '23 10/30/2017 $ 89.21 $ 86.23 $ 89.12 $ 2.70 $ 2.86 $ 3.02 $ 3.50 11/6/2017 $ 90.00 $ 88.14 $ 88.34 Source: June 15, 2018; Value-Line 11/13/2017 $ 92.48 $ 88.28 $ 90.05 11/20/2017 $ 90.25 $ 88.93 $ 89.52 11/27/2017 $ 92.30 $ 89.23 $ 91.01 NYSE:PNW Mean 12/4/2017 $ 91.52 $ 88.66 $ 90.75 LT Growth(%) 4.54 4.85 5.00 3.46 0.64 4 12/11/2017 $ 91.28 $ 88.20 $ 89.54 Source: SNL/S&P Global 12/18/2017 $ 89.90 $ 84.81 $ 85.14 12/25/2017 $ 85.55 $ 84.26 $ 85.18 1/1/2018 $ 85.55 $ 82.02 $ 82.42 6.00 ----*--- 6.00 1/8/2018 $ 83.18 $ 79.11 $ 79.22 1/15/2018 $ 79.92 $ 78.55 $ 79.08 1/22/2018 $ 81.33 $ 78.81 $ 80.94 1/29/2018 $ 80.65 $ 77.69 $ 77.73 5.50 5.51) 2/5/2018 $ 78.35 $ 73.81 $ 76.29 2/12/2018 $ 78.88 $ 75.61 $ 78.69 2/19/2018 $ 80.41 $ 75.92 $ 80.15 -~e ....r-G1 2/26/2018 $ 80.83 $ 76.06 $ 76.92 Cl 5.00 5.00 c!
~
3/5/2018 $ 78.3) $ 75.21 $ 76.38 I-
..I 5' 3/12/2018 $ 78.00 $ 75.96 $ 77.97 3/19/2018 $ 80.14 $ 77.40 $ 77.76 3/26/2018 $ 80.21 $ 77.73 $ 79.80 .f.fAJ 4.50 4/2/2018 $ 80.54 $ 78.~2 $ 79.75 4/9/2018 $ 80.37 $ 77.14 $ 78.14 4/16/2018 $ 80.73 $ 77.55 $ 78.02 4/23/2018 $ 81.85 $ 77.95 $ 81.61 4.0D 4.00 4/30/2018 $ 81.61 $ 78.24 $ 80.20 ...._"\ .(\ ,:'I ,:, !'o.'b ~'ti .....~ ~ ~ ~ ...._'b ...._ra.
5/7/2018 $ 80.48 5/14/2018 $ 78.39 76.96 75.97 78.12 76.54
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5/21/2018 $ 78.63 $ 75.82 $ 78.39 Date 5/28/2018 $ 80.29 $ 77.48 $ 77.58 6/4/2018 $ 77.86 $ 73.90 $ 74.40 - L T Growth - LTGrawlh 6/11/2018 $ 76.21 $ 73.41 $ 76.11 6/18/2018 $ 78.44 $ 75.69 $ 78.29 6/25/2018 $ 81.25 $ 78.24 $ 80.56 7/2/2018 $ 82.41 $ 80.57 $ 82.38 Mm1mum $ 13.41 $ 14.40 Maximum $ 92.48 $ 91.01 Mean $ 83.23 Source: i'ahooFmance, July 18, 2018
Schedule AHG - 4 18-KCPE-480-RTS Portland General (POR}
Date Hii:h Low Close 1/B/E/S Growth Estimates POR 7/3/2017 $ 45.83 $ 44.55 $ 44.87 Current Qtr. 8.30%
7/10/2017 $ 44.99 $ 44.20 $ 44.59 Next Qtr. -2.30%
7/17/2017 $ 46.35 $ 44.41 $ 46.35 Current Year -3.90%
7/24/2017 $ 46.16 $ 44.27 $ 44.44 Next Year 7.30%
7/31/2017 $ 45.57 $ 44.45 $ 45.46 Next 5 Years (per annum) 2.65% 0.023 8/7/2017 $ 46.57 $ 45.24 $ 45.90 Past 5 Years (Iler annum} 5.87%
8/14/2017 $ 46.68 $ 45.61 $ 46.40 Source: YahooFinance; July 18, 2018 8/21/2017 $ 47.40 $ 46.27 $ 47.14 8/28/2017 $ 47.60 $ 47.02 $ 47.33 9/4/2017 $ 47.91 $ 47.10 $ 47.87 9/11/2017 $ 48.22 $ 46.60 $ 46.96 9/18/2017 $ 47.04 $ 45.48 $ 45.58 Value-Line EPS DPS 9/25/2017 $ 46.31 $ 45.53 $ 45.64 Past 10 Years 4.00% 9.00%
10/2/2017 $ 46.54 $ 45.52 $ 46.07 Past 5 Years 3.50% 3.50%
10/9/2017 $ 47.07 $ 45.95 $ 46.25 Est '15-'17 to '21-'23 4.00% 6.00%
10/16/2017 $ 46.35 $ 44.70 $ 45.37 10/23/2017 $ 47.68 $ 45.25 $ 47.67 2017 2018 2019 '21 to '23 10/30/2017 $ 48.18 $ 47.10 $ 47.76 $ 1.34 "$ 1.42 $ 1.50 $ 1.80 11/6/2017 $ 48.69 $ 47.48 $ 48.28 Source: June 15, 2018; Value-Line 11/13/2017 $ SO.II $ 48.35 $ 49.34 11/20/2017 $ 49.45 $ 48.38 $ 48.48 11/27/2017 $ 49.85 $ 48.23 $ 49.49 NYSE:POR Mean 12/4/2017 $ 49.84 $ 48.23 $ 48.68 LT Growth(%) 3.02 3.00 3.80 2.25 0.63 3 12/11/2017 $ 48.87 $ 47.00 $ 47.79 Source: SNL/S&P Global 12/18/2017 $ 48.12 $ 45.36 $ 45.61 12/25/2017 $ 45.83 $ 45.00 $ 45.58 1/1/2018 $ 45.65 $ 43.63 $ 43.86 ~-5() -- --*----- -- -- ------ ,.50 1/8/2018 $ 44.02 $ 42.38 $ 42.62 1/15/2018 $ 42.99 $ 42.25 $ 42.40 1/22/2018 $ 42.85 $ 41.89 $ 42.27 1/29/2018 $ 42.47 $ 41.00 $ 41.40 ,.oo ,:oo 2/5/2018 $ 41.62 $ 39.40 $ 40.47 2/12/2018 $ 41.41 $ 39.77 $ 41.20 2/19/2018 $ 41.14 $ 39.86 $ 41.08 'ie 2/26/2018 $ 41.27 $ 39.41 $ 39.74 l.50 3.50 3/5/2018 $ 40.42 $ 39.02 $ 39.18 "...
I-3/12/2018 $ 40.09 $ 39.07 $ 40.05 3/19/2018 $ 41.06 $ 39.09 $ 39.11 3/26/2018 $ 40.76 $ 39.27 ~ 40.51 l.00 3,00 4/2/2018 $ 40.66 $ 39.56 $ 40.21 4/9/2018 $ 40.54 $ 39.18 $ 40.22 4/16/2018, $ 41.21 $ 40.07 $ 40.17 4/23/2018 $ 42.59 $ 40.15 $ 42.33 -, - - - - - - -- . - -------- -- --.-- ~,..-------, - -- 2.51) 4/30/2018 $ 42.93 $ 41.63 $ 42.76 2.5D
(:, "'I ,(lo
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5/7/2018 $ 42.81 5/14/2018 $ 41.09
$ 40.56 $ 41.05
$ 39.66 $ 39.78
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5/21/2018 $ 41.92 $ 39.66 $ 41.87 0.ilt!I 5/28/2018 $ 42.93 $ 41.46 $ 42.27 6/4/2018 $ 42.41 $ 39.99 $ 40.21 - LT Growth - LT Growth 6/11/2018 $ 41.43 $ 39.60 $ 41.40 6/18/2018 $ 42.59 $
- 41.12 $ 42.41 6/25/2018 $ 43.29 $ 42.39 $ 42.76 7/2/2018 $ 43.96 $ 42.47 $ 43.95 Mtmmum $ 39.02 $ 39.11 Maximum $ 50.11 $ 49.49 Mean $ 43.97 Source: I' ahooFmance, July 18, 2018
ScheduleAHG- 4 18-KCPE-480-RTS Xcel Energy IXEL}
Date High Low Close 1/B/E/S Growth Estimates XEL 7/3/2017 $ 46.06 $ 45.18 $ 45.69 Current Qtr. 4 .40%
7/10/2017 $ 46.08 $ 45.41 $ 45.92 Next Qtr. 2.10%
7/17/2017 $ 47.42 $ 45.85 $ 47.42 Current Year
- 5.70%
7/24/2017 $ 47.70 $ 46.55 $ 47.16 Next Year 6.60%
7/31/2017 $ 48.12 $ 46.96 $ 47.97 Next 5 Years (per annum) 5.86%
8/7/2017 $ 48.72 $ 47.79 $ 48.19 Past 5 Years (per annum) 4.18%
8/14/2017 $ 49.22 $ 48.19 $ 49.00 Source: YahooFinance; July 18, 2018 8/21/2017 $ 49.60 $ 48.93 $ 49.37 8/28/2017 $ 49.70 $ 49.19 $ 49.36 9/4/2017 $ 50.30 $ 49.17 $ 50.23 9/11/2017 $ 50.56 $ 48.59 $ 49.08 9/18/2017 $ 49.10 $ 47.29 $ 47.41 Value-Line EPS DPS 9/25/2017 $ 47 .97 $ 46.69 $ 47.32 Past 10 Years 5.50% 4.50%
10/2/2017 $ 47.80 $ 46.86 $ 47-.39 Past 5 Years 5.00% 5.50%
10/9/2017 $ 49.08 $ 47.37 $ 48.61 Est '15-'17 to '21-'23 5.50% 5.50%
10/16/2017 $ 49.41 $ 48.26 $ 49.26 10/23/2017 $ 49.83 $ 48.56 $ 49.21 2017 2018 .2019 '21 to '23 10/30/2017 $ 49.92 $ 48.93 $ 49.59 $ 1.44 $ 1.52 $ 1.60 $ 1.90 11/6/2017 $ 50.57 $ 49.29 $ 50.20 Source: June 15, 2018; Value-Line 11/13/2017 $ 52.22 $ 50.13 $ 50.89 11/20/2017 $ 51.05 $ 50.35 $ 50.71 11/27/2017 $ 51.84 $ 50.61 $ 51.36 NASDAQ : XEL Mean 12/4/2017 $ 51.58 $ 50.40 $ 51.20 LT Growth(%) 5.67 5.60 6.30 5.00 0.40 7 12/11/2017 $ 51.45 $ 50.16 $ 50.78 Source: SNL/S&P Global 12/18/2017 $ 50.86 $ 48.12 $ 48.25 12/25/2017 $ 48.41 $ 47.53 $ 48.11 5.90 5.00 1/1/2018 $ 48.36 $ 46.63 $ 46.79 1/8/2018 $ 47.22 $ 45.06 $ 45.15 1/15/2018 $ 45.86 $ 44.89 $ 45,13 5.80 5.80 1/22/2018 $ 46.10 $ 45.12 $ 45.70 1/29/2018 $ 45.78 $ 44.45 $ 44.48 2/5/2018 $ 44.75 $ 41.51 $ 43.35 2/12/2018 $ 44.88 $ 43.04 $ 44.68 5.70 5.70 2/19/2018 2/26/2018 44.82 44.92 43.50 $ 44.77 42.65 $ 43.03
]
3/5/2018 $ 44.02 $ 42.57 $ 43.28 5.50 5.60 3/12/2018 $ 44 .23 $ 43.23 $ 44.13 3/19/2018 $ 45.19 $ 43.66 $ 43.74 3/26/2018 $ 45.87 $ 43.81 $ 45.48 5.50 5.50 4/2/2018 $ 45.99 $ 44.68 $ 45.47 4/9/2018 $ 45.80 $ 43.93 $ 44.48 4/16/2018 $ 46.01 $ 44.49 $ 45.10 4/23/2018 $ 47.38 $ 45.12 $ 47.10 o.40 ' - - - , -
- 4/30/2018 5/7/2018 5/14/2018 47.37 46.54 45.41 45.93 $ 46.39 44.58 $ 45.26 .
43.44 $ 43.70
~ ~ ~ ~
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5/21/2018 $ 45.30 $ 43.28 $ 45.19 Dal@
5/28/2018 $ 45.87 $ 44.63 $ 44.74 6/4/2018 $ 44.93 $ 42.27 $ 42.72 - LT Growth - LT'Growth 6/11/2018 "$ 43.43 $ 41.99 . $ 43.33 6/18/2018 $ 44.39 $ 43.25 $ .43.85 6/25/2018 $ 46.24 $ 43.90 $ 45.68 7/2/2018 $ 46.63 $ 45.70 $ 46.59 Mm1mum $ 41.SI $ 42.12 Maximum $ 52.22 $ 51.36 Mean $ 46.77 Source: YaliooFmance, July 18, 2018
Schedule AHG - 5 18-KCPE-480-RTS Internal Rate of Return Analysis Summary 2 3 4 5 6 7 8 9 IO II 12 13 14 Short-Term Growth EPS Growth Long-Term Growth Years 5 Through 250 Average ST Growth LT Growth 2019 2018
- 2020 2021 2022 2023 2024 2025 2021 through 2264 IRR Price Estimate Estimate Dividends YearO Year! Year2 Year3 Year4 Year5 Year6 Year 7 through Year 250 Allete Inc. 7.82% $ 74.78 5.53% 4.30% $ 2.34 $ (72.44) $ 2.47 $ 2.61 $ 2.75 $ 2.90 $ 3.03 $ 3.16 $ 2,215;022 Alliant Energy Corp. 8.23% $ 41.56 6.06% 4.30% $* 1.42 $ (40.14) $ 1.51 $ 1.60 $ 1.69 $ 1.80 $ 1.87 $ 1.95 $ 1,371,882 Ameren Corp. 8.19% $ 58.17 6.47% 4.30% $ 1.94 $ (56.23) $ 2.07 $ 2.20 $ 2.34 $ 2.49 $ 2.60 $ 2.71 $ 1,902,961 American Electric Power Co. 8.51% $ 70.22 5.30% 4.30% $ 2.63 $ (67.59) $ 2.77 $ 2.92 $ 3.07 $ 3.23 $ 3.37 $ 3.52 $ 2,468,566 2.96 $
- 3.16 $ 3.26 $ 3.37 $ 3.51 $ 3.66 $ 2,569,661 Consolidated Edison Inc. 8.12% $ 80.75 3.27% 4.30% $ (77.79) $ 3.06 $
Duke Energy Corp. 9.44% $ 81.78 4.61% 4.30% $ 3.80 $ (77.98) $ 3.98 $ 4.16 $ 4.35 $ 4.55 $ 4.75 $ 4.95 $ 3,473,721 Edison International 8.39% $ 69.71 4.95% 4.30% $ 2.57 $ (67.14) $ 2.70 $ 2.83 $ 2.97 $ 3.12 $ 3.25 $ 3.39 $ 2,379,957 El Paso Electric Co. 7.42% $ 54.44 5.45% 4.30% $ 1.52 $ (52.92) $ 1.60 $ 1.69 $ 1.78 $ 1.88 $ 1.96 $ 2.04 $ 1,434,756 IDACORP Inc. 7.39% $ 89.08 4.37% 4.30% $ 2.56 $ (86.52) $ 2.67 $ 2.79 $ 2.91 $ 3.04 $ 3.17 $ 3.30 $ 2,318,531 NorthWestern Corp. 8.58% $ 56.88 3.54%. 4.30% $ 2.30 $ (54.58) $ 2.38 $ 2.47 $ 2.55 $ 2.64 $ 2.76 $ 2.88 $ 2,018,138 OGE Energy Corp. ' 9.47% $ 34.06 5.60% 4.30% $ 1.54 $ (32.52) $ 1.63 $ 1.72 $ 1.81 * $ 1.92 $ 2.00 $ 2.08 $ 1,461,907 Pinnacle West Capital Corp. 8.28% $ 83.23 4.70% 4.30% $ 3.02 $ (80.21) $ 3.16 $ 3.31 $ 3.47 $ 3.63 $ 3.79 $ 3.95 $ 2,770,873 Portland General Electric Co. 7.93% $ 43.97 3.92% 4.30% $ 1.50 $ (42.47) $_ 1.56 $ 1.62 $ 1.68 $ 1.75 $ 1.82 $ 1.90 $ 1,335,299 Xcel Energy Inc. 8.18% $ 46.77 5.63% 4.30% $ 1.60 $ (45.17) $ 1.69 $ 1.79 $ 1.89 $ 1.99. $ 2.08 $ 2.17 $ 1,520,796 Mean 8.28%
Min 7.39%
Max 9.47%
Column 1) Proxy group
- 2) Internal rate of return calcuation -- Investors' discount rate that equates the stock price to the stream of future dividends
- 3) Average stock price July 2, 2017 through July 3, 2018
- 4) Average of short-term growth rates used in first 5 years
- 5) Long-term nGDP growth rate used after 2024
- 6) 2019 dividends reported by Value-Line
- 7) Year O Cashflow; stock price less 2019 dividend 8 through 11 ) Annual cashflow growing at short-term growth rate 12 through 250) Annual cashflow growing at long-term growth rate
STATE OF KANSAS )
) ss.
COUNTY OF SHAWNEE )
VERIFICATION Adam H. Gatewood, being duly sworn upon his oath deposes and says that he is the Managing Financial Analyst for the State Corporation Commission of the State of Kansas, that he has read and is familiar with the foregoing Direct Testimony, and that the statements contained therein are true and correct to the best of his knowledge, information and belief.
Adam H. Gatewood Senior Managing Financial Analyst Utilities Division State Corporation Commission of the State of Kansas Subscribed and sworn to before me this 12th day of September, 2018.
A
- PAMELA J. GRIFFETH
~ Notary Public - State of Kanse11 My Appl. Expires <> t'-' 7, o/
My Appointment Expires: August 17, 2019
CERTIFICATE OF SERVICE 18-KCPE-480-RTS I, the undersigned, certify that a true and correct copy of the above and foregoing Direct Testimony was served by electronic service on this 12th day of September, 2018, to the following:
JAMES G. FLAHERTY, ATTORNEY MARTIN J. BREGMAN ANDERSON & BYRD, L.L.P. BREGMAN LAW OFFICE, L.L.C.
216 S HICKORY 311 PARKER CIRCLE PO BOX 17. LAWRENCE, KS 66049 OTTAWA, KS 66067 mjb@mjbregmanlaw.com Fax: 785-242-1279 jflaherty@andersonbyrd.com GLENDA CAFER, ATTORNEY TERRIPEMBERTON,ATTORNEY CAFER PEMBERTON LLC CAFER PEMBERTON LLC 3321 SW 6TH 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 THOMAS J. CONNORS, ATTORNEY AT LAW TODD E. LOVE, ATTORNEY 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 tj.connors@curb.kansas.gov t.love@curb.kansas.gov
- DAVID \IV. NICKEL, CONSUMER COUNSEL SHONDA RABB 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 d.nickel@curb.kansas.gov s.rabb@curb.kansas.gov DELLA SMITH ROBERT J. HACK, LEAD REGULATORY COUNSEL CITIZENS' UTILITY RATEPAYER BOARD KANSAS CITY POWER & LIGHT COMPANY 1500 SW ARROWHEAD RD ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (64105 TOPEKA, KS 66604 PO BOX 418679 Fax: 785-271-3116 KANSAS CITY, MO 64141-9679 d.smith@curb.kansas.gov Fax: 816-556-2787 rob.hack@kcpl.com
CERTIFICATE OF SERVICE 18-KCPE-480-RTS DARRIN R. IVES, VICE PRESIDENT, REGULATORY RONALD A. KLOTE, DIRECTOR, REGULATORY AFFAIRS AFFAIRS KANSAS CITY POWER & LIGHT COMPANY KANSAS CITY POWER & LIGHT COMPANY ONE KANSAS CITY PLACE ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (64105 1200 MAIN, 19TH FLOOR PO BOX 418679 KANSAS CITY, MO 64105 KANSAS CITY, MO 64141-9679 Fax: 816-556-2110 Fax: 816-556-2110 ronald.klote@kcpl.com darrin.ives@kcpl.com TIM RUSH, DIR. REGULATORY AFFAIRS ROGER W. STEINER, CORPORATE COUNSEL KANSAS CITY POWER & LIGHT COMPANY KANSAS CITY POWER & LIGHT COMPANY ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (64105 ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (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 tim.rush@kcpl.com roger.steiner@kcpl.com ANTHONY WESTENKIRCHNER, SENIOR PARALEGAL BRIAN G. FEDOTIN, DEPUTY GENERAL COUNSEL KANSAS CITY POWER & LIGHT COMPANY KANSAS CORPORATION COMMISSION ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (64105 1500 SW ARROWHEAD RD PO BOX 418679 TOPEKA, KS 66604 KANSAS CITY, MO 64141-9679 Fax: 785-271-3354 Fax: 816-556-2787 b.fedotin@kcc.ks.gov anthony.westenkirchner@kcpl.com AMBER SMITH, CHIEF LITIGATION COUNSEL ROBERT VINCENT, LITIGATION COUNSEL KANSAS CORPORATION COMMISSION KANSAS CORPORATION COMMISSION 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 785-271-3167 Fax: 785-271-3354 a.srnith@kcc.ks.gov r.vincent@kcc.ks.gov JUDY JENKINS HITCHYE, MANAGING ATTORNEY ANDREW J. FRENCH, ATTORNEY AT LAW KANSAS GAS SERVICE, A DIVISION OF ONE GAS, INC. SMITHYMAN & ZAKOURA, CHTD.
7421 W 129TH ST 7400 W 110TH ST STE 750 OVERLAND PARK, KS 66213-2713 OVERLAND PARK, KS 66210-2362 Fax: 913-319-8622 Fax: 913-661-9863 judy.jenkins@onegas.com andrew@smizak-law.com JAMES P. ZAKOURA, ATTORNEY CATHRYN J. DINGES, CORPORATE COUNSEL SMITHYMAN & ZAKOURA, CHTD. WESTAR ENERGY, INC.
7400 W 110TH ST STE 750 818 S KANSAS AVE OVERLAND PARK, KS 66210-2362 PO BOX 889 Fax: 913-661-9863 TOPEKA, KS 66601-0889 jim@smizak-law.com Fax: 785-575-.8136 cathy.dinges@westarenergy.com
CERTIFICATE OF SERVICE 18-KCPE-480-RTS DAVID L. WOODSMALL WOODSMALL LAW OFFICE 308 E HIGH ST STE 204 JEFFERSON CITY, MO 65101 Fax: 573-635-7523 david.woodsmall@woodsmalllaw.com Isl Pamela Griffeth Pamela Griffeth Administrative Specialist
Enclosure IV to WM 19-0008 Joint MotiorHo Approve Stipulation (Docket No. 15-WCNE-093-GIE)
(28 pages)
20150210140017 Filed Date: 02/10/2015 State Corporation Commission of Kansas BEFORE THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS In the Matter of the 2014Wolf Creek )
Decommissioning Cost Study as Provided by Wolf )
Creek Nuclear Operating Corporation on August 29, ) Docket No. 15-WCNE-093-GIE 2014 in Accordance with the Commission's Order in )
Docket Number 163,561-U on December 9, 1992 )
and the Commission's Order in Docket No. 13- )
- WCNE-204-GIE on June 13, 2013. )
JOINT MOTION TO APPROVE STIPULATION AND AGREEMENT AND TO CONVERT THE EVIDENTIARY HEARING IN THIS DOCKET TO A SETTLEMENT HEARING OR CANCEL THE HEARING COMES NOW the Staff of the State Corporation Commission of the State of Kansas.
("Staff' and "Commission," respectively), Wolf Creek Nuclear Operating Corporation ("Wolf
& Lig~t Company ("KCP&L"), and Kansas Electric Power Cooperative, inc. ("KEPCo")
(collectively referred to as the "Joint Movants") and respectfully move the* Commission for an Order approving the Stipulation and Agreement ("S&A") filed contemporaneously with this Motion. The S&A is attached as Exhibit 1. The Parties also request the Commission convert the February 24, 2015 evidentiary hearing set out in the procedural schedule contained in the October 16, 2014 Order Setting Procedural Schedule and Design.ating Prehearing Officer in this docket to a settlement hearing:.
I. INTRODUCTION *
- 1. On August 29, 2014, 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 1
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 *
- 2. Westar, KCP&L, KEPCo and CURB filed petitions to intervene, which were granted.
- 3. The Joint Movants and the Citizens' Utility Ratepayer Board ("CURB) held several conference calls and met on February 9, 2015 to discuss settlement of this docket.
Following negotiations, the Joint Movants entered into an S&A {attached as Exhibit 1) 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 Joint Movants and CURB also discussed a separate, future issue regarding the content of the 2017 triennial decommissioning cost study.
filing. Although CURB is not a signatory to the S&A, CURB has advised the Joint Movants that it does not oppose the S&A.
- 4. Further, the Joint Movants have submitted pre-filed testimony to support* the
. S&A, no party to the docket opposes the S&A, and the Joint Movants have included sufficient information within the S&A to respond to the Commission's five threshold questions used in reviewing an S&A for reasonableness.
See Docket No. 13-WCNE-204-GIE, In the Matter of a Generic Proceeding Regarding Wolf Creek Nuclear Operating Corporation to Receive Infonnation Concerning Spent Fuel, Pursuant to the Commission's May 12, 2012 Order in Docket No. 12-WCNE-136-GIE, Order Closing Docket, issued Jun. 13, 2013, Ordering ,r A.
2
II. THE S&A MEETS THE LEGAL STANDARDS NECESSARY FOR COMMISSION APPROVAL OF SETTLEMENT AGREEMENTS AND SHOULD BE APPROVED.
- 5. An order of the Commission must afford parties their due process rights, be supported l:,y substantial competent evidence, be in the public interest, conform_wit_h applicable law and if the order impacts rates those rates must be just and reasonable.
- 6. All parties participated fully in the proceeding and no violation of due process claims has been raised. The S&A is either supported or not opposed by all parties to the docket. As noted e~rlier, the following parties* intervened in this docket: Staff, Wolf Creek, Westar, KEPCo, KCP&L and CURB. A procedural schedule was set on October 16, 2014 providing opportunity for Direct Testimony by the applicants, Wolf Creek, Westar, KEPCo and KCP&L, responsive Direct Testimony by Staff and CURB, Cross-Answering Testimony by Staff and CURB, and Rebuttal Testimony by the applicants. Additionally, all parties to the case participated on the January 30, 2015 conference call and in the Settlement Conference on February 9, 2015 wherein they- discussed a joint motion and settlem~nt agreement. Follow..:up communication regarding the joint motion and settlement agreement included all parties to the case. Therefore, the Joint Movants to the S&A believe that appropriate and sufficient opportunity was provided for all parties to the docket to be heard on any reasons for opposing the S&A.
- 7. The S&A is supported by substantial competent evidence .. A decision of the
(.
Commission is unsupported by substantial competent evidence "only when the evidence shows the [Commission's] determination 'is so wide of the mark as to be outside the realm of fair debate.' " 2 The Kansas Supreme Court has also stated that the Commission "is not obligated to 2
Zinke.& Trumbo, Ltd v. Kansas Corp. Comm'n, 242 Kan. 470,474 (1988) (quoting Kansas-Nebraska Natural Gas Co. v. Kansas Corp. Comm 'n, 217 Kan. 604, 617).
3
render its finding of fact in minute detail . . . [h]owever, we require its findings to be specific 3
enough to allow judicial review ~f the reasonableness of the order." As noted above, the Joint Movants have provided the decommissioning cost study as well as the testimony of three witnesses, all o(which support the S&A. The cost for decommissioning funding*of.$765,060,000 and the escalation rat<? of 3 .15% agreed to in the S&A are supported by substantial competent evidence. As part of the Application in this docket, Wolf Creek provided the decommissioning cost study supporting the decommissioning cost estimate. Staff witness Leo Haynos testified in support of the cost estimate provided in the Application. Haynos Direct, at p. 12. On behalf of the applicants, Gregg Clizer testified that 3.15% is the appropriate escalation rate. Clizer Direct, at pp.
3-7. Staff witness Adam Gatewood testified in support of the escalation rate. Gatewood Direct, at pp. 2-3.
- 8. The S&A conforms with applicable law. An Order is "lawful" if it is within the
- statutory authority of the commission, .and if the *prescribed statutory and proc~dural
- rules are 4
followed in making the Order. The S&A deals with the decommissioning cost estimate required to be submitted to the Commission by Kansas statute for utilities owning a nuclear facility. Thus, the subject matter of the S&A is clearly within.the Commission's authority. It is also clear that the applicable statutory and procedural rules have been followed. The S&A is the result of negotiations among and is supported or. not opposed by all of the parties to this proceeding.
Commission approval of the S&A under these circumstances would clearly be in compliance with applicaf?le law.
- 9. The S&A results in just and reasonable rates. Approval by the Commission of the S&A in. this docket will not have an immediate effect on rates charged to Kansas c1;1stomers.
Rate impact will not* occur until each owner company files its individual dockets wherein the Id at 475.
4 Central Kansas Power Co. v. State Corp. Comm'n, 221 Kan. 505, Syl. 1 (1977).
new decommissioning accrual will be included in their revenue requirement. See, e.g., Gatewood Direct, at pp. 1-2. However, because the decommissioning cost elements being stipulated to in this docket are fair, reasonable,. and fully supported by the eyidence, inclusion of the same in rates later should not cause such rates to become unjust or unreasonable.
- 10. Whether the results of the Stipulation are in the public interest. The Joint Movants agree the terms of this S&A are in the public interest and should _be approved by tq.e Commission. Each party to this proceedi_ng has a duty to protect the interests of the party it represents. The companies have* a duty *to both their customers and shareholders. CURB
. represents the interests of residential and small commercial customers. The Staff is in the unique position of being required to weigh and balance the interests of the companies, the utility customers, and any other party to a proceeding. By signing or not opposing this S&A, these parties represent to the Commission that the total effect of the terms of the S&A represents an
- equitable balancing of the interests of all p~ies. It is also in the public interest to avoid the cost of litigation in this* matter and the unanimous settlement promotes administrative efficiency and reduces related litig~tion costs. Thus, the S&A is in the public interest, and should be_adopted by the Commission in its entirety.
- 11. As indicated above, the following testimony has been submitted in this docket in support of the S&A:
- Direct Testimony of Gregg Clizer for Wolf Creek, KCP&L, Westar and KEPCo.
- Direct Testimony and Testimony in Support of Settlement of Leo Haynos for Staff.
- Direct Testimony of Adam Gatewood for Staff.
.5
- Testimony in Support of Settlement. of Mary Britt Turner for Wolf Creek, .
KCP&L, Westar and KEPCo.
- 12. The Joint Movants ask that the testimony listed in par~graph 11 and the 2014 Decommissioning Cost Analysis performed by TLG Services, Inc. and submitted :with the Application be admitted into the record. Because a settlement supported or unopposed by all parties is being presented andthe terms of the S&A are supported by testimony in the record, the Parties do not believe that it is necessary for the Commission to hold an evidentiary hearing in this docket. The Parties believe that with the addition of testimony \ supporting the S&A to be filed on February 12, 2015, the record will allow the Commission to approve the S&A without the need for a settlement hearing. Thus, the Parties r~quest the Commission either convert the February 24, 2015 evidentiary hearing set out in the procedural schedule contained in the October 16, 20.14 Order Setting Procedural Schedule and Designating Prehearing Officer in this docket to a settlement hearing or cancel the hearing altogether if the Commission determines a hearing is unnecessary given the record.
WHEREFORE, the Joint Movants respectfully request that the Commission approve the S&A, convert the evidentiary hearing on this matter to a settlement hearing or cancel the hearing altogether, and for any further relief the Commission shall deem just and appropriate.
Respectfully *submitted, David Springe, (#15619) Samuel Feather (#25475)
Ni~i Christopher, (# 19311) Litigation Counsel Citizens' Utility Ratepayer Board Kansas Corporation Commission 1500 SW Arrowhead Road 1500 SW Arrowhead Road Topeka, KS 66604 Topeka, KS 66604-4027 (785) 271-3200 (785) 271.:3196 _
(785) 271-3116 Fax (785) 271-3167 Fax 6
Cathryn J.'Dinges, (#20848) William G. Riggins, (#12080)
Corporate Counsel General Counsel Kansas Gas and Electric Co., Kansas Electric Power Cooperative, Inc.
d/b/a Westar Energy, Inc. P.O. Box 4877 __
818 South Kansas Avenue Topeka, KS 66604-0877 Topeka, KS 66612 (785) 273-7010 (785) 575-1986 (785) 271-4888 (Fax)
(785) 575-8136 (Fax)
Debbie L. Rendell Roger W. Steiner, (#26159)
Wolf Creek Nuclear Operating Corporation Corporate Counsel .
1550 Oxen Lane NE, PO Box 411 Kansas City :£lower & Light Company Burlington, KS 66839 1200 Main Street, 16th Floor _ *
(620) 364,.4105 Kansas City, MO 64105 (620) 364-4017 (Fax) (816) 556-2314 (816) 556-2787 (Fax) 7
Exhibit 1 BEFORE THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS In the Matter of the 2014Wolf Creek )
Decommissioning Cost Study as Provided by Wolf )
Creek Nuclear Operating Corporation on Augu~t 29, ) Docket No. 15-WCNE-093-GIE 2014 in Accordance with the Commission's Order in )
Docket Number 163,561-U on December 9, 1992 )
and the Commission's Order in Docket No. 13- )
WCNE-204.:.GIE on June 13, 2013. )
STIPULATION AND AGREEMENT This Stipulation and Agreement ("S&A") is _entered into by and between the Staff of the State Corporation Commission of the State of Kansas ("Staff' and "Commission," respectively),
Wolf Creek Nuclear Operating Corporation ("Wolf Creek"), Kansas Gas and Electric Company d/b/a Westar Energy ("Westar"), Kansas City Power & Light Company ("KCP&L"), and Kansas Electric Power Cooperative, Inc. ("KEPCo") (cqllectively referred to as the "Parties").
- 1. On August 29, 2014, 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. The December 9, 1992 Order directed the filing of a decommissioning cost study every three years after September l, 1993.
- 2. Westar, KCP&L, KEPCo and CURB filed petitions to intervene, which were granted.
- 3. On January 30, 2015, the Parties held a conference call to discuss settlement of the issues in this docket. The Parties also discussed settlement at the Settlement Conference held on February 9, 2015. The terms of the resulting S&A are set forth below.
1.
Exhibit 1 I. TERMS OF THE STIPULATED SETTLEMENT AGREEMENT
- 4. This S&A 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.
- 5. 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, which is hereby incorporated by reference. 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 individual company dockets, separate from the instant docket.
- 6. Westar, KCP&L and KBPCo 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 yeat that the decommissioning*costs will occur.
- 7. 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; however, just as the review process is currently split into two phases - a joint phase for the decommissioning cost study and the escalation factor, and a utility-specific phase for the individual utility financing plans - the utilities may determine to ~le certain of the requirements separately at the time of the joint filing _so long as all 11 requirements are covered.
- 8. 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. CURB, while not .a See Direct Testimony of Leo M. Haynos, filed Jan. 5, 2015, p. 12, lines 8-23.
2
Exhibit 1 signatory, has indicated its support of such discussions. The Parties believe that a resolution can be achieved and suggest the following schedule be adopted by the Commission:
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.
On or before September 1, 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.
- 9. In support of the S&A, the Parties pre-filed the testimony and schedules of the following witnesses:
- Direct Testimony of Gregg Clizer for Wolf Creek, KCP&L, Westar and KEPCo.
- Direct Testimony artd Testimony in Support of Settlement of Leo Haynos for Staff.
- . Direct Testimony of Adam Gatewood for Staff.
- Testimony in Support of Settlement of Mary Britt Turner for Wolf Creek, KCP&L, Westar and KEPCo.
The Application also included the 2014 Decommissioning Cost Analysis performed by TLG Services, Inc., which cost study is the primary subject of this docket.
II. RESERVATIONS
- 10. Except as specified in, this S&A, none of the Parties to the agreement shall be
. deemed to have approved or acquiesced in any. question of the Commission authority, 3
. ' Exhibit 1
- IN* WITNESS HERETO, the Parties have executed and approved this S&A effective by subscribing their signatures below.
Respectfully submitted, David Springe, (#15619) Samuel Feather (#25475)
Niki Christopher, (#19311) Litigation Counsel Citizens' .U:tility Ratepayer Board Kansas Corporation Commission
. 1500 SW . Arrowhead Road 1500 SW Arrowhead Road Topeka, KS 66604 Topeka, KS 66604-4027 (785) 271-3200 (785) 271-3196 (785) 271-3116 Fax (785) 271-3167 Fax Cathryn J. Dinges, (#20848) . William G. Riggins, (#12080)
Corporate Counsel General Counsel Kansas Gas and Electric Co., Kansas Electric Power Cooperative, Inc.
d/b/a Westar Energy, Inc.
- P.O. Box 4877 818 South Kansas Avenue Topeka, KS 66604-0877 Topeka, KS 66612 * . (785) 273-7010
. (785).575-198.6 (785) 271-4888 (Fax)
(785) 575-8136 (Fax)
/4/ *;e~ 'HI.* Steu,e,,.
Debbie L. Rendell Roger W. Steiner, (#26159)
Wolf Creek Nuclear Operating Corporation Corporate Cpunsel
-1550 Oxen Lane NE, PO Box 411 Kansas City Power & Light Company Burlington, KS 66839 1200 Main Street, 16th Floor (620) 364-4105 _Kansas City, MO 64105 (620) 364-4017 _(Fax) (816) 556-2314 (816) 556-2787 (Fax) 5
./i Enclosure V to WM 19-0008 Order Approving Unanimous Settlement Agreement (Docket No. 18-KCPE-480-RTS)
(34 pages)
20181213103959 Kansas Corporation Commission THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS Before Commissioners: Shari Feist Albrecht, Chair Jay Scott Emler Dwight D. Keen In the Matter of the Application of Kansas )
City Pow~r & Light Company to Make ) Docket No. 18-KCPE-480-RTS Certain Changes in its Charges for Electric )
Service. )
ORDER APPROVING UNANIMOUS SETTLEMENT AGREEMENT 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:
- l. On May l, 2018, Kansas City Power & Light Company (KCP&L) filed for a $32.9 million revenue increase, including property tax rebasing. 1 As a result of the Commission's approval of the merger of KCP&L's parent company, Great Plains Energy, Inc. 'with Westar Energy, Inc., on May 24, 2018 (the merger), KCP&L reduced its requested revenue increase to
$22.6 million.2 This Application was accompanied by the direct testimony from 14 witnesses.
- 2. On June 26, 2018, Darrin Ives, Vice President - Regulatory Affairs for KCP&L, filed supplemental direct testimony to reflect the Commission's approval of the merger and reduced. KCP&L's requested revenue requirement, including property tax rebasing, from
$32,948,941 to $22,673,415. 3
- 3. The Commission has jurisdiction to supervise and control electric public utilities, as defined in K.S.A. 66-IOla, doing business in Kansas. 4 The Commission has the power to 1 Application, May I, 2018, ,r 3.
2 Supplemental Direct Testimony of Darrin R. Ives, June 26, 2018, p 2.
3 Id. .
4 K.S.A.66-101.
require all electric utilities governed by the Electric Public Utilities Act to establish and maintain just and reasonable rates. 5
- 4. Notice of.the proposed rate increase, public hearing, and evidentiary hearing was provided by mail for each customer in KCP&L's service territory as well as by publishing notice in the major newspapers in the region. The Commission received comments from the public at the August 23, 2018 public hearing in Overland Park. The Commission also received 876 public comments through its Office of Public Affairs and Consumer Protection. 6 The Commission issues this Order with due consideration of those comments.
- 5. The Citizens' Utility Ratepayer Board (CURB); Wal-Mart Stores, Inc .. (Walmart);
Midwest Division - OPRMC, LLC d/b/a Overland Park Regional Medical Center (OPRMC);
Kansas Gas Service; American Fuel & Petrochemical Manufacturers (AFPM); Magellan Pipeline Company, L.P. (Magellan); Petroleum Marketers and Convenience Association of Kansas, Inc.
(PMCA); Olathe Public Schools USD 233; Johnson Co.unty Community College; Spring Hill School District USD 230; and Blue Valley Schools - Unified School District No. 229 were granted intervention.
- 6. On September 12, 2018, David Banks filed direct testimony on behalf of Olathe Public Schools USD 233; Johnson County Community College; Spring Hill School District USD 230; and Blue Valley Schools- Unified School District No. 229 (the Schools). After opining that schools are paying inordinately high rates for electric service, Banks advocated for a separate schools tariff for educational institutions to take service as a separate customer class. 7 5 K.S.A. 66-IOlb.
6 The public comments were entered into the record by the Notice of Filing of Public Comments on October 23, 2018.
7 Direct Testimony of David VI_. Banks, Sept. 12, 2018, p. 13.
2
- 7. Also, on September 12, 2018, Paul Raab filed direct testimony on behalf of Kansas Gas Service; Steve Chriss filed direct testimony oll behalf of Walmart; Andrea C. Crane, Brian Kalcic, and Stacey Harden filed testimony on behalf of CURB; and Tim Stringer, Justin Grady, William Baldry, Adam Gatewood, Roxie McCullar, Justin .
Prentiss, Darren Prince,. Brad Hutton,
- Joshua Frantz, Chad Unrein, Andria Jackson, and Dr. Robert Glass filed direct testimony on behalf of .Commission Staff (Staff).
- 8. On September 19,2018, Raab, Kalcic, and Chriss filed cross-answering testimony.
- 9. On October 3, 2018, Albert Bass, Jr., Charles Caisley, Brian File, Jeffrey Fle~nor, Melissa Hardesty, Darrin Ives, Ronald Klote, Bradley Lutz, .Marisol Miller, Linda Nunn, Tim Rush, Thomas Sullivan, Dane Watson, and Kimberly Winslow filed rebuttal testimony on behalf ofKCP&L.
.10~: On October 15, 20i8, .Staff, CURI3, KCP&L, Walmart, OPRMC, the Schools, AFPM, Magellan, PMCA, and Kansas Gas Service (the Signatories) filed a Joint Motion for Approval of Unanimous Settlement Agreement. The Unanimous Settlement Agreement (Unanimous Settlement Agreement), is attached as Attachment A and incorporated by reference.
- 11. The Signatories agree that the Unanimous Settlerrterit Agreement resolves* all revenue requirement issues in this Docket. 8 Under the terms of the Unanimous Settlement Agreement, KCP&L will experience an overall annual revenue requirement decrease of $10.7.
million, before the Property Tax Surcharge (PTS) rebasing. The $10.7 mill.ion includes $7.5 million of merger savings, as required by the Settlement in the 18-KCPE-095-MER Docket.
Including the PTS, under the Unanimous Settlement Agreement, KCP&L's revenue requirement decreases by $3,916,417. 9 9
8
,1.
Unanimous Settlement Agreement, Oct. 15, 2018,, 12.
Id.,
3
.12. Other key terms included in the Unanimous Settlement Agreement are:*
- KCP&L will distribute a one-time bill credit of$36,915,958 for tax savings related to the period of January 1, 2018, through December 27, 2018, to customers with the first billing cycle that starts 60 days after this Order; 10
- KCP&L's approved ROE will be 9.3%, resulting in an overall rate of return of 7.07% and a capital structure with a 50.91 %-49.09% debt-equity ratio. 11
- KCP&L will create a regulatory liability to capture the K~nsas jurisdictional amount of depre~iation expense included in KCP&L's revenue requirement
. beginning with the retirement of the Montrose units to accumulate in the regulatory liability account until new customer rates are established in KCP&L's next KCP&L general rate case. 12
.* KCP&L's Kansas jurisdictional, non-tran*smission related property tax ~xpense in base rates is $46,558,678. 13
- The Residential Customer charge increases from $14.00 to $14.25. 14
- The Signatories will ask the Commission to initiate a general, investigation to evaluate whether KCP&L should implement a school tariff. 15
- KCP&L will collaborate with Staff and Walmart to explore alternative rate designs for commercial customers, focusing on more transparent and simple .
demand/energy rates. 16 10 Id., ,r 9.
11 Id., ,r 8.
12 Id., ,r 12.
13 Id., ,r 19.
14 Id., ,r 22; see also Direct Testimony of Robert H. Glass, Sept. 12, 2018, p. 14..
15 Unanimous Settlement Agreement,,r 34.
16 Id., ,r 35.
4
- The Signatories agree that the Unanimous Settlement Agreement resolves all revenue allocation, class cost of service and rate design issues under this Docket. 17
- 13. On October 15, 2018, Andrea Crane (CURB), Darrin Ives (KCP&L), David Banks (the Schools), and Justin Grady and Dr. Robert Glass (Staff) each filed testimony in support of the Unanimous Settlement Agreement.
- 14. On October 22, 2018, KCP&L filed an estimate of the rate case expense incurred and expected to be incurred in this Docket, indicating that it had originally anticipated $1,603,100 in total rate case expense. However, as a result of the Unanimous Settlement Agreement, KCP&L has lowered its expected total rate case expense to $632,272. 18
- 15. On October 24, 2018, the Commission held a hearing on the Unanimous Settlement Agreement. KCP&L, Staff, CURB, Walmart, OPRMC, the Schools, Kansas Gas Service, and AFPM, Magellan, and PMCA appeared by counsel. KCP&L, Kansas Gas Service, the Schools, and Staff made opening statements. The Commission heard live testimony from 4 witnesses: Ives (KCP&L), Banks (the Schools), and Grady and Glass (Staff).
- 16. The law generally favors compromise and settlement of disputes between parties when they enter into an agreement knowingly and in good faith to settle the dispute. 19 When approving a settlement, the Commission must make an independent finding that the settlement is supported by substantial competent evidence. in the 'record as a whole, establishes just and reasonable rates, and i~ in the public interest. 20 17 Id., ,r 36.
18 KCP&L Rate Case Expense Filing, Oct. 22, 2018, p. 2.
- 19Krantzv. Univ. of Kansas, 271 Kan. 234, 241-42 (2001).
20 Citizens' Util. Ratepayer Bd v. Kansas Corp. Comm 'n, 28 Kan. App. 2d 313, 316 (2000), rev denied March 20, 2001.
5
- 17. The Unanimou~ Settlement Agreement is a "Unanimous settlement agreement" as defined by K.A.R. 82-l-230a. Therefore, there is no need to apply the five-factor test. 21
- 18. Substantial competent evidence possesses something of substance. and relevant consequence, which furnishes a substantial basis of fact to reasonably resolve the issues. 22 Whether another trier of fact could have reached a different conclusion given the same facts is irrelevant; a court can only find that a Commissio.n decision is not supported by substantial competent evidence when the evidence shows "the [Commission's] determination is so wide of the mark asto be outside the realm of fair debate."23 The Commission has reviewed the record in this Docket that consists of pre-filed testimony from a total of 34 witnesses, including 15 on behalf of KCP&L, live testimony of 4. witnesses, and the Joint Motion for Approval of Unanimous Settlement Agreement, supported by testimony from Aridrea Crane (CURB), Darrin Ives (KCP&L), David Banks (the Schools), and Justin Grady and Dr. Robert Glass (Staff).
- 19. Having reviewed the record as a whole, the Commission finds and concludes that
\
substantial competent evidence supports approval of the Unanimous Settlement Agreement in its entirety. Every electric public utility in Kansas is required to provide reasonably efficient and sufficient service and establish just and reasonable rat~s. 24 Under Kansas Supreme Court precedent, rates must fall within a "zone of reasonableness" which balances t_he interests of investors versus ratepayers, present versus future ratepayers, and the public :interest.25 The Signatories agree the Unanimous Settlement Agreement results in just and reasonable rates. 26 Accordingly, we find the 21 See Order Approving Contested Settlement Agreement, ,r,r 9~ IO (280 Order), Docket No. 08-ATMG-280-RTS (May 12, 2008) ..
22 Farmland Indus., Inc. v. Kansas Corp. Comm 'n, 25 Kan.App.2d 849, 852 (1999).
23Id. at 851. *
- 24 K.S.A. 66-lOlb.
25 Kansas Gas, 239 Kan. 483,488 (1986).
26 Testimony in Support ofUnanimous Settlement Agreement of Andrea C. Crane, Oct. 15, 2018, ,r 12; Testimony in Support ofUrtanimous Settlement Agreement of Darrin R. Ives, Oct. 15, 2018, ,r 12; Testimony in Support of Unanimous Settlement Agreement of Justin T. Grady, Oct. 15, 2018, ,r 11.
6
Unanimous Settlement Agreement fairly represents a balance of the interests of the Signatories, reaches a reasonable result that is supported by the evidence, and is in the public interest.
- 20. The requirement of just and reasonable rates incorporates the "zone of reasonableness" test, and is used to determine whether the rate is within an elusive range of reasonableness in calculating a fair rate of retum. 27 The Commission acts within its discretion in 28 finding an "in-between point, where the rate is most fair to the utility and its customers." The Commission considered the competing interests it must take into account in setting rates, and finds the agreed upon revenue requirement under the Unanimous Settlement Agreement falls within the "zone of reasonableness." There is substantial evidence in the record that the agreed-upon rates will provide KCP&L with sufficient revenues and cash flows to meet its financial obligations, yet will keep rates as low as possible while maintaining reliable service for its customers. Accordingly, the Commission finds and concludes that the approval of the Unanimous Settlement Agreement will result in just and reasonable rates for KCP&L and its customers.
- 21. The Commission finds that approval of the Unanimous Settlement Agreement is in the public interest. The Signatories agree the terms of the Unanimous Settlement Agreement are in the public interest and should be approved by the Commission.29 The Signatories explain that the terms of the Unanimous Settlement Agreement represent an equitable balancing of the interests of
° all Signatories.3 Furthermore, the public interest is served by minimizing the cost of litigation, and passing those cost savings on to ratepayers. 31 27 Kansas Gas, 239 Kan. at 490.
28Jd.
29 Testimony in Support of Unanimous Settlement Agreement of Andrea C. Crane, ~112-13; Testimony in Support of Unanimous Settlement Agreement ofDarrin R. Ives, 113; Testimony in Support of Unanimous Settlement Agreement of Justin T. Grady, ~ 13.
3
°Testimony in Support of Unanimous Settlement Agreement of Andrea C. Crane, ~ I I; Testimony in Support of Unanimous Settlement Agreement of Darrin R. Ives, 113; Testimony in Support of Unanimous Settlement Agreement of Justin T. Grady,~~ 13-14.
31 See Testimony in Support of Unanimous Settlement Agreement of Justin T. Grady, 1 15.
7
- 22. The Commission finds that the agreed-upon rates under the Unanimous Settlement Agreement will provide KCP&L with sufficient revenue to meet its financial obligations and provide safe and reliable service at just and reasonable rates to its customers. After considering all of the terms of the Unanimous Settlement Agreement, the Commission finds and concludes that it is in the public interest. The Unanimous Settlement Agreement is a balanced agreement that is fair to all affected parties. Therefore, the Commission finds the proposed rate design is fair and reasonable, and is in the public interest.
- 23. After a careful review and consideration of the evidence in the record, the Commission finds that the attached Unanimous Settlement Agreement is supported by substantial competent evidence in the record as a whole, will result in just and reasonable rates, and is in the public interest. The Commission approves the Unanimous Settlement Agreement in its entirety.
- 24. The new rates and tariffs will be effective December 20, 2018.
- 25. As part of the Unanimous Settlement Agreement, the Signatories requested a general investigation docket to evaluate whether KCP&L should establish a separate tariff or tariffs for schools. The Signatories anticipated the initiation of this general investigation docket by July 1, 2019. The Commission agrees that such a general investigation is appropriate. Accordingly, the I
Commission directs KCP&L and the Schools to file comments in this docket delineating the scope of the general investigation into a possible school tariff by February 5, 2019. Those comments should be limited to 12 pages. Staff is directed to file a Report and Recommendation based on those comments by March 18, 2019.
THEREFORE, THE 'COMMISSION ORDERS:
A. The Unanimous Settlement Agreement is approved in its entirety. The terms of the attached Unanimous Settlement Agreement are incorporated into this Order.
8
B.
- KCP&L's Kansas jurisdictional, non-transmission related property tax expense in base rates is $46,558,678 and shall be the basis for property tax balance used for purposes of future PTS filings when the new rates take effect on December 20, 2018.
C. The $10.7 million overall revenue requirement decrease as provided under the Unanimous Settlement Agreement is approved. After rebasing amounts previously recovered through KCP&L's Property Tax Surcharge, the Commission approves a total revenue decrease of
$3,916,417.
D.* KCP &L and the Schools are each directed to file comments suggesting the scope of a general investigation into a possible school tariff. Those comments are due by February 5, 2019, and should be limited to 12 pages. Staff is directed to file a Report and Recommendation
(
based on those comments by March 18, 2019.
E. Any party may file and serve a petition for reconsideration pursuant to the require~ents and time lim~ts established by K.S.A.77-529(a)(l). 32 F. The Commission retains jurisdiction over the subject matter _and parties to enter further orders as it deems necessary.
BY THE COMMISSION IT IS SO ORDERED.
Albrecht, Chair; Emler, Commissioner; Keen, Commissioner 12/l?/2018 Dated:
LynnM. Retz Secretary to the Commission BGF 32 K.S.A. 66-l 18b; K.S.A.77-503(c); K.S.A. 77-53 l(b).
9
ATTACHMENT A BEFORE THE STATE CORPORATION COMMISSION OF THE STATE OF KANSAS In the Matter of the Application of Kansas )
City Power & Light Company to Make ) Docket No. 18-KCPE-480-RTS Certain Changes in Its ~barges for Electric )
Service. )
UNANIMOUS SETTLEMENT AGREEMENT As a result of discussions between the parties to this d.ocket, the Staff of the State Corporation Commission of the State of Kansas ("Staff' and "Commission," respectively),
Kansas City Power & Light Company ("KCP&L" or "the Company"), the Citizens' Utility Ratepayer Board ("CURB"), Wali:nart, Inc. ("Walmart"), Midwest Division - OPRMC, LLC d/b/a Overland Park Regional Medical Center ("OPRMC"), Olathe Unified School District 233
("USD 233"), Spring Hill Unified School District 230 ("USD 230"), Blue Valley Unified School District 229 ("USD 229"), and Johnson County Community College ("JCCC"), (referred together as "Schools"), 1 Kansas Gas Service, Inc., a division of ONE Gas, Inc. ("KGS"), and American Fuel & Petrochemical Manufacturers ("AFPM"), Magellan Pipeline Company, L.P.
("Magellan"), and Petroleum Marketers and Convenience Association of Kansas, Inc. ("PMCA")
(referred to collectively as the "Signatories" or the "Signatory Parties"), hereby submit to the Commission for its consideration and approval the following Unanimous Settlement Agreement
("Settlement"):
I. KCP&L'S APPLICATION
. 1. On May 1, 2018, KCP&L filed an Application with the Commission to make certain changes in its rates and charges for electric service, which was docketed as the above-1 USD 233, USD 230, and USD 229 sign this agreement subject to approval by their respective Boards ofEducation.
These entitities commit to notify the Commission of board approvals a*s they occur through filings in*this docket.
I
ATTACHMENT A captioned proceeding. The filing was made in accordance with Kansas Statutes Annotated
("K.S.A.") §66-117, and Kansas Administrative Regulations ("K.A.R.") § 82-1-231 (b )(3).
2~ The schedules filed with KCP&L's .Application indicated a gross revenue
- requirement deficiency of $26.2 million, excluding the rebasing of property taxes, based upon normalized operating results for the test year ending September 30, 2017, adjusted for known and measurable changes in revenues, operating and maintenance expenses, cost of capital and taxes, and .other adjustments explained . in the
- testimony and schedules supporting this .
. Application. The Company's requested increase was $32.9 million with the inclusion of the property tax reb~sing.
- 3.
- On June 26, 2018, KCP&L filed supplemental testimony incorporating into its Application the terms of the agreement approved by the Co111mission in Dp_cket No. 18-KCPE-095-MER2 issued on May 24, 2018 ("18-095 Docket",18-095 Settleme,nt Agreement", and "18-095 Order"). 3 With the 18-095 Settlement Agreement incorporated into KCP&L's position, the revenue requirement deficiency became $15.9 million, excluding property tax rebasing.
- 4. Staff filed its direct testimony on September 12, 2018, recommending* a revenue decrease of approximately $J .2 million, excluding property tax rebasing. CURB filed_ its direct and cross-answering testimony on September 12, 2018 and September 19, 2018, respectively; recommending a revenue decrease of approximately $12.2 million, ,excluding property tax rebasing. Staff and CURB also addressed policy and rate design issues. Other intervenors filed direct and cross-answering testimony primarily addressing rate design issues, 2
In the Matter of the Application of Great Plains Energy Incorporated, Kansas City Power & Light Company and Westar energy, Inc. for Approval ofthe Merger of Westar Energy, Inc. and Great Plains Energy Incorporated 3
On Aug. 10, 2018, KCP&L filed the Corrected Supplemental Direct Testimony* of Darrin Ives to correct a transposed number contained in Mr. Ives' Supplemental Direct testimony.
2
ATTACHMENT A
- 5. Consistent with the Commission's Procedural Order, KCP&L filed rebuttal testimony on October 3, 2018. The parties held settlement discussions on October 9 - 10, 2018, and reached this Settlement, as described below.
II. TERMS OF SETTLEMENT AGREEMENT
- 6. The Signatory Parties have agreed to a total revenue requirement amount, revenue allocations, and -rate design adjustments, without specifically addressing the underlying issues and disagreements regarding those issues, except as set forth herein. This Settlement resolves all issues in this matter, with such Settlement providing no precedent for future cases as to the_
underlyi_ng issues or positions of the parties on those issues. "In the event the Commission either does ~ot approve this Settlement in total, or materially change*s the Settlement terms, then the Settlement shall be voidable by any Signatory negatively affected by such modification. The following set forth the terms of this Settlement:*
A. Revenue Requirement
- 7. The Signatory Parties agree that KCP&L's overall annual revenue requirement decrease will be $10.7 million, not including the Property Tax Surchaq~e ("PTS") rebasing. This amount includes $7 .5 million of merger savings, as required under the 18-095 Settlement Agreement. With the PTS included, the revenue requirement decrease is $3,916;4 l 7.
(1) - ROE, Capital Structure, Cost of Debt
- 8. The Signatory Parties agree that KCP&L;s revenue requirement is based on the
~
cost of capital as follows:
3
ATTACHMENT A
' Return on Rate Base A B C Percent of Component Weighted Capitalization Cost Avg. Cost I Debt 50.91 % . 4.93% 2.51%
2 Common Equity 49.09% 9.30% 4.56%
3 Totals 100.00% 7.07%
(2) Tax Cut and Jobs Act
- 9. KCP&L will provide to customers a one,-time bill credit of $36,915,958 for tax savings related to the period of January 1, 2018, through December 27, 2018. It will be distributed to customers with the first billing cycle that starts 60 days after the Commission issues its order in this case. KCP&L agrees to sync up the timing of these tax credits with the timing of the merger related up-front bill credits that will be provided pursuant to the
- Commission's Merger Order and to use the Merger Order processes to determine the tax credit amounts. If the effective date of new rates from this case is different than December 27, 2018, the amount refunded to customers shall be adjusted to reflect the number of days between January 1, 2018, and the effective date of rates from this case using the annual amount of
$37,354,878 for such calculation.
- 10. Amortization expense associated with the excess accumulated deferred income taxes will be recorded by the Company using the following periods:
EXCESS DEFERRED INCOME TAXES ("EDIT") AMORTIZATIO NS IN KCP&L-KS REVENUE REQUIREMENT -TOTAL COMPANY AMOUNTS Increase/ (Decrease)
EDIT Amount to Amortize Years/Amortize to Tax Expense Average Rate Assumption Method Plant-Protected ($403,638,981) ("ARAM") $ (10,362,524)
Plant-Unprotected ($130,978,754) 5 yr $ (26,195,751)
NOL $65,110,179 ARAM $2,187,842 4
ATTACHMENT A Miscellaneous ($1,205,360) 10 yr $ (120,536)
Total $ (34,490,969)
- 11. The Signatory Parties agree that EDIT amortization from July 1, 2018 through the effective date of rates will be established in a regulatory liability and will not be recorded to the income statement until the Company addresses the amortization of this deferred
- regulatory Iia.bility in the next KCP&L general rate case filed after the KCP&L 2018 general rate case is completed.
(3) Depreciation
- 12. For settlement purposes only, Staffs depreciation rates will be adopted .
Additionally, KCP&L will create a regulatory liability to capture the Kansas jurisdictional amount of depreciation expense included in KCP&L's revenue requirement beginning when the Montrose units are retired and depreciation expense is no longer recorded to the income statement associated with the Montrose units. The depreciation amounts ~ill accumulate in the regulatory liability account until new customer rates are established in the next KCP&L general rate case filed after this 2018 general rate case is completed. At that time, the regulatory liability account will be closed into accumulated depreciation. Additionally, the closing of this regulatory liability into accumulated depreciation will be reflected in rates that are established in that rate case.
(4) Revenue Adjustments
- 13. The Signatories agree that KCP&L's sales revenues and unit sales will be utilized for purposes of setting rates.
- 14. KCP&L and Staff will work together to resolve normalization data requirement shortfalls noted by Staff in this case. Prior to the filing of the next rate case filing, the data issues will be resolved to the statisfaction of all parties ..
5
\
ATTACHMENT A (5) Clean Charge Network
- 15. The Signatories agree that the CCN tariff rate schedule proposed by the Company and the rates contained therein shall be adopted. The Settlement does not address inclusion or exclusion .in rate base or cost of service of the plant, costs, or expenses related to the CCN. The Settlement* does not address recovery of the CCN except for the tariffed rate and therefore any party can assert any position regarding CCN cost recovery in KCP&L's next general rate proceeding after the five year merger moratorium.
(6) AccountingAdiustments
- 16. There will be no change in .the Wolf Creek NDT funding level from the amount currently in rates. This does not reflect agre~ment with any particular method in calculating the appropriate funding level.
- 17. KCP&L will continue the accounting for Asset*Retirement Obligations ("ARO")
as adopted in May 2018 for th~ KCP&L-KS jurisdiction. ARO settlements will reduce the ARO regulatory asset for settlement costs as they are incurred and are recorded to the reserve at the time of payment rather than waiting until the end of the life of the ARO.
- 18. The CIP/Cybersecurity Tracker as approved in Docket No. 15-KCPE-115-RTS will continue in this case. The base amount of the tracker is set at $4,592,958 (Total Company) for CIP and $933,304 (Total Company) for Cybersecurity.
(7) Other Issues
- 19. The Signatories agree_ that the Kansas jurisdictional, non . .transmission related property tax expense in base rates is $46,558,678 and shall be the basis for property tax balance used for purposes of future PTS filings for the time period the new rates are applicable. This 6
. ATTACHMENT A
. includes the additional property tax rebase amount of $~,783,583 to be included in base rates in this case.
- 20. For the purposes of calculating KCP&L's pension tracker going forward, the Signatories agree that the base rates agreed to in this Settlement include the following expenses associated with KCP&L's pension and OPEB plans (amounts provided are total Company):
OPEB Expense: . $1,852,965 Amortization of Tracker 1: ($1,357,860)
Pension Expense: $45,653,251 Amortization of Tracker l': $1,858,774 TRACKER BALANCES AS OF JUNE 30, 2018:
OPEB Tracker 1 ($6,789,299)
Tracker2 $0 Pension Tracker 1 $9,293,870 Tracker 2 ($76,278,533)
- 21. A list of regulatory assets and liabilities and their associated amortization periods is attached hereto as Attachment A.
- 22. The Signatories agree this Settlement resolves ~II revenue requirement issues.
7
ATTACHMENT A B. Allocation of Revenue Requirement Among Customer Classes and Rate Design Matters
(]) Revenue Allocation
- 23. The Signatories agree to the following revenue decrease allocation among the customer classes:
Proposed Proposed Revenue from Existing KANSAS RATE GROUP Decrease Decrease Rates LARGE GEN SVC TOTAL * $162,402;701 . $(1,625,875) -1.001%
MEDIUM GEN SVC TOTAL $69,285,911 $(693,648) -1.001%
SMALL GEN SVC TOTAL $43,958,196 $(527,498) -1.200%
RESIDENTIAL TOTAL $295,423,478 . $(1,001,043) -0.339%
Metered TOTALS $571,070,286 $(3,848,065)
Lighting TOTAL: $6,827,468 $(68,352) -1.001 %
TOTAL $577,897,754 $(3,916,417) -().678%
- 24. In . accepting the allocation of the revenue decrease and resulting rates, the Signatories agree that this Settlement does not indicate any specific class cost of service methodology or approach.
- (2) Residential Rate Design
- 25. The* Residential Customer charge shall increase to $14.25. The remaining residential class revenue requirement decrease will be allocated to the energy blocks. The residential rates are as follows:
8
ATTACHMENT A Proposed Present Rates Rates
-0.684%
CUSTOMER CHARGE (per month)
One Meter - Rate Code (2RS1A; 2RSDA; 2RS6A; 2RW6A; 2R01A): 14.00 14.25 Two Meter - Rate Code (2RS2A; 2RS3A; 2R\/v7A): 14.00 14.25 ENERGY CHARGE (per kWh)
All rates less Other Use - SUMMER - Rate Code ( All less 2R01A):
First 1000 kWh per month 0.10751 0.10677 01.er 1000 kWh per month 0.10751 0.10677 Other Use - For all kWh - SUMMER - Rate Code (2R01A): 0.12551 0.12465 General Use -WINTER - Rate Code {2RS1A; 2RSDA):
First 1000 kWh per month 0.08300 0.08243 01.er 1000 kWh per month 0.08300 0.08243 General Use and Space Heat - One Meter'- WINTER - Rate Code (2RS6A; 2RW6A):
First 1000 kWh per month 0.07474 0.07423 01.er 1000 kWh per month 0.06524 0.06524 General Use and Space Heat-Two Meter-WINTER- Rate Code (2RS2A; 2RS3A; 2R\/v7A):
First 1000 kWh per month 0.07474 0.07423 01.er 1000 kWh per month 0.06527 0.06527 Other Use* For all kWh - WINTER* Rate Code (2R01A):
- 0.09862 0.09795 Separately Metered Space Heat - Rate Code (2RS2A; 2RS3A; 2R\/v7A):
For all kWh- SUMMER 0.10751 0.10677 For all kWh -WINTER 0.06524 0.06524 Time Of Day (Frozen) - Rate Code (2TE1A):
Customer Charge 20.00 19.86 On-Peak - SUMMER 0.17621 0.17500 Off-Peak - SUMMER 0.07370 0.07320 For all kWh -WINTER 0.07705 0.07652
- 26. KCP&L will offer the following optional pilot rates as filed: Residential TOU rate _
and Residential Demand rate. With regard to those pilot rates the Signatories agree that:
- a. KCP&L will be permitted to establish a regulatory asset or . liability account to track the revenue impact of rate switching for customers switching to- either the Residential TOU or Re~ide~tial Demand rates.
Further, customers will be allowed a one-year opt-out option consistent with the rebuttal testimony of KCP&L witness Kimberly Winslow.
- b. Marketing and customer education costs associated with these tariffs and the Residential Distributed Generation tariff will be recorded in a regulatory asset account with a budget cap of $2.2 million (Kansas jurisdiction). KCP&L will track and may seek recovery of these costs 9
ATTACHMENT A during KCP&L's next general rate case. KCP&L will collaborate with Staff with regard to marketing and education efforts, thereby providing, Staff with the opportunity to provide input on the reasonableness of those efforts and expenditures in. advance of proceeding. As part of this effort, KCP&L will provide detailed, line item budgets for expenses incurred in rriarketing and education efforts. Staff may request additional information*
related to these or any other expenses associated with marketing and custom.er education costs. In the event Staff disagrees with the level of expenditures, KCP&L shall have the right to argue the prudency of those
- expeditures during the next general rate proceeding.,
- 27. With regard to Residential Distributed Generation, the Signatories agree to the following:
- a. Adopt a three-part rate with modifications proposed by Staff witness Bob Glass:
(i) the summer and winter demand charges shall be $9.00/kW and $3.00/kW, respectively; (ii) the customer charge shall be $14.25 (equal to Residential Customer Charge for general use);
(iii) the energy charge shall be $0.07688 energy charge per _
kWh; and (iv) the demand measurement shall be a 60-minute interval.
(v) The demand billing period shall be the daily hours of 2:00 pm through 7:00 pm Central Time, except for_ weekends, 10
ATTACHMENT A New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day.
- b. The Company will report annually to Staff and CURB the following information for the Residential Distributed Generation rate:
(i) number of residential DG customers taking service from the rate, (ii) the total demand and energy charges paid during the year, (iii) annual energy consumption data by customer, and (iv) annual total bill amounts (less riders) by customer.
This same information will be provided annually regarding the Residential
/
TOU rate and the Residential Demand rates.
(3) Non-Residential Rate Design
- 28. The Signatories agree that the rate design for the Non-Residential decrease, established in the Revenue Requirement section above, will be applied in the following manner.
- a. Small General Service (i) Decrease all components equally based on class revenue allocatioq
- b. Medium & Large General Service (i) A reduction to all energy charges by 2%
(ii) Increase the remaining non-energy bill components on an equal percentage basis to achieve the class revenue reduction.
11
ATTACHMENT A C. Lighting (i) Decrease all components equally to all non-LED lighting rates bas_ed on class revenue allocation.
- 29. The Signatories agree to KCP&L's LGS Off-Peak rider as proposed with revisions as presented by KCP&L witness Miller in rebuttal testimony.
(4) LED Lighting
- 30. The Signatories accept Staffs recommendation to approve* KCP&L's. plan and related pricing for street and private area lighting with price modifications and regulatory accounting treatment for revenues and costs as proposed by Staff witness Ellis.
(5) Programs
- 31. With regard to the Solar Subscription Program the Signatories agree as follows:
- a. KCP&L shall be authorized to pursue a build option or Power Purchase Agreement ("PPA") for solar resources.
- b. KCP&L's selection of either a build option or PPA for solar resources will be based on least cost to customers.
- c. The revenue requirement for inclusion in rates for a Company-owned solar built project will be levelized over the life of the project if the cost of the solar resource exceeds $10 million. For projects under this amount, parties reserve their ability to address the methodology for inclusion in KCP&L's revenue requirement at the time the solar resource is included in a future general rate proceeding.
- d. KCP&L will not build or enter into a PPA for a solar project until the project ,is 75% subscribed, and the cost of any unsubscribed portion will 12
ATTACHMENT A be borne 75% by KCP&L and 25% by customers. The 25% borne by customers will be reflected in the ECA.
- 32. With regard to the Renewable Energy Rider the Signatories agree as follows:
- a. The Signatories agree to KCP&L's redesigned tariff and related provisions as described in the rebuttal testim.ony of KCP&L witness. Brad Lutz, 1 which provides for:
(i) Accommodation of the revisions belo*w recommended by Walmart Witness Steve Chriss.
- 1. Revision of the process to first enroll customers for a resource tranche of the program to be apportioned on an allocation of the available resource based on expressed interest.
- 2. Inclusion of a renewal provision that gives the participating customer the option to renew its
.Participation prior to offering that capacity to other
- customers.
- 3. Use of enrollment agreements with twenty-year terms. Lesser terms of five-year, -ten-year, and fifteen-years will be allowed at a cost premium to the twenty-year rate.
- 4. Inclusion of more flexible transfer terms as noted in Paragraph 4 of the Definitions and Conditions 13
ATTACHMENTA section of the exemplar tariff in the rebuttal testimony of Brad Lutz.
(ii) The redesigned tariff shall:
- 1. Be consistent with the Westar DRPS tariff.
- 2. Use separate Participation Agreements.
- 3. Allow for smaller participation limits.
- a. Requiring a peak demand of 200 kW and subscription in 200 kW increments up to 1,000 kW and 500 kW increments thereafter.
- b. Participation agreement will include provisions allowing Schools, municipalities, and goverments to .aggregate accounts to meet participation limits.
- 4. Include a KCP&L commitment to make a subsequent tariff filing to establish the renewable resource, term, and price. KCP&L will also provide the price premium for shorter term enrollment. Staff and CURB agree to make all reasonable efforts to review and provide a recommendation concerning the filing within the time associated with the PPA offer terms.33.
The Signatories agree to KCP&L's Standby Service Rider as filed.
- 34. The Signatories agree to the following with regard to the Schools:
- a. The Comn:iission should initiate a general investigative docket on or before July 1, 2019, to evaluate whether KCP&L should implement one or more School tariffs and how such a tariff(s) should be designed and 14
ATTACHMENT A implemented. If the investigation results in the implementation of School tariffs that are not revenue neutral to KCP&L, then a regulatory asset/liability will be created to allow KCP&L recovery of those revenues and associated deferred return at the weighted-average cost of capital at the time of the next general rate proceeding follow~ng the rate moratorium period resulting from the Merger.
- b. While KCP&L has the ability to dedicate in-house personnel to the study of the school tariff issue, the Signatories understand that investigative proceedings often become more expansive than originally anticipated, resulting in the necessity for engagement of 'outside technical and legal consultants. As such, KCP&L shall be allowed the opportunity to seek a regulatory asset to recover those costs relating to the engagement of outside consultants resulting from the investigation, should such engagement become necessary.
- c. If KCP&L impleme~ts one or more School tariffs, KCP&L agrees to separately identify Schools tariff customers in the class cost of service study filed in its -next rate case.. *However, during the investigation contemplated in paragraph 33.a., the parties may explore- alternative methods of providing transparency regarding School rates and may agree to inodify or eliminate the requirement to identify School tariff customers in the Company's class cost of service study.
- d. KCP&L agrees to assign key account representatives to assist the Schools in evalutating usage characteristics to determine the appropriate rate 15
ATTACHMENT A schedules for each of the respective Schools' accounts and to discuss other rate opportunities such as the renewable energy rider. Key account representatives will be promptly assigned and will contact each of the Schools no later than 30 days following a final order approving this agreement.
- 35. KCP&L will collaborate with Walmart and Staff during the moratorium period on rate design issues for the purpose of exploring alternative rate designs for non-residential, non-lighting, rate classes. Specifically, KCP&L will review demand/energy rates and rates that may offer more transparency and simplicity.
- 36. The Signatories agree this Settlement resolves all revenue allocation, class cost of service and rate design issues.
C. Modification to the Procedural Schedule.
- 37. Due to the presentation of this Settlement that resolves all contested issues, the Signatories recommend to the Commission the following:
(I) The prehearing conference scheduled for October 15, 2018, the
/
evidentiary hearings scheduled for October 23-26, 20 I 8, and post-hearing briefing of this matter be cancelled.
(2) The prefiled testimony submitted in this case, including testimony filed in I
support of this Settlement Agreement on October 15, 2018, be entered into the record of this docket.
.(3) The Commission issue its decision based upon the written record.
16
ATTACHMENT A (4) If the Commission prefers to hold a hearing on this Settlement Agreement, the Commission convert the October 23, 2018 evidentiary hearing date to a hearing on the Settlement Agreement.
III.
- MISCELLANEOUS PROVISIONS A. The Commission's Rights
- 38. Nothing in this Settlement 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, and any statutory obligation, including the obligation to ensure that KCP&L is providing efficient and sufficient service at just and reasonable rates.
B. Waiver of Cross-Examination
- 39. In the event the Commission conducts a hearing, the Signatory Parties waive cross-examination on all testimony filed prior to the filing of this Settlement Agreement.
C. Negotiated Settlement
- 40. This Settlement represents a negotiated settlement that fully resolves the issues raised in this proceeding. The Signatory Parties represent that the terms of this Settlement constitute a fair and reasonable resolution of the issues addressed herein. Except as specified herein, the Signatory Parties shall not be prejudiced, bound by, or in any way affected by the terms of this Settlement (a) in any future proceeding; (b) in any proceeding currently pending under a separate docket; and/or (c) in this proceeding should the Commission decide to not approve this Settlement in the instant proceeding. If the Commission accepts this Settlement Agreement in its entirety and incorporates the same into a formal order without material modification, the Signatory Parties shall be bound by its terms and the Commission's order 17
.. ATTACHMENT A incorporating its terms as to all issues addressed herein and in accordance with the terms hereof, and will not appeal the Commission's order on these issues.
D.
- Interdependent Provisions
- 41. The provisions of this Settlement have resulted from negotiations among the Signatory Parties and are interdependent. In the event that the Commission does not approve and adopt the terms of this Settlement in total or materially changes the Settlement terms,
- the Settlement shall be voidable and no Signatory Party hereto shall be bound, prejudiced, or in any way affected by .any of the agreements or provisions hereof. Further, in the event the Commission does not approve and adopt the terms of this Settlement in total, this Settlement shall be considered privileged and not admissible in evidence or made a part of the record in any proceeding. In the event of a termination pursuant to this Section, the Settlement shall be null and void and of no further effect, with all rights, duties, and obligations of the Signatory Parties thereafter restored as if this Settlement had never been executed; provided, that the Signatory Parties may, in the sole discretion of each Party, agree to attempt to modify the Settlement in a
- manner that would resolve the adver~e effect of the material change of condition.
18
ATTACHMENT A IN WITNESS THEREOF, the Signatory Parties have executed and approved this Settlement Agreement, effective as of the 12th day of October 2018, by subscribing their signatures below.
By: . /d/ f ) ~ ie 'IIIU Darrin R. Ives '
Vice President, Regulatory Affairs Kansas City Power & I;.,ight Company One Kansas City Place 1200 Main Street - 31st Floor Kansas City, MO 64105 Telephone: (816) 556~2522 Facsimile: (816) 556-2110 darrin.ives@kcpl.com KAN~AS_;CITY POWER & LIGHT COMPANY.
By: /d/ 'i&/6¢1/UIU#t Robert Vincent, #26028 Senior Litigation Counsel 1500 SW Arrowhead Road Topeka, KS 66604 Telephone: (785) 271-3273 .
Facsimile: (785) 271-3354 r.vincent@kcc.ks.gov STAFF OF THE KANSAS CORPORATION COMMISSION By:
David W. Nickel, # 11170 Todd Love, #13445 Consumer Counsel ,
Citizens' Utility Ratepayer Board 1500 SW Arrowhead Road Topeka, KS 66604 Telephone: (785) 271-3200 Facsimile: (785) 271-3116 d.nickel@~URB.kansas.gov CITIZENS' UTILITY RATEPAYER BOARD 19
ATTACHMENT A By:
David L. Woodsmall, #15944 Woodsmall Law Office 308 E. High Street, Suite 204 Jefferson City, MO 65101 Telephone: (573) 797-0005 david.woodsmall@woodsmal Ilaw .com WALMART, INC. and MIDWEST DIVISION-OPRMC, LLC D/B/A OVERLAND PARK REGIONAL MEDICAL CENTER By: /,/-jZ). ~
James P. Zakoura, #07644 Andrew J. French, #24680 Smithyman & Zakoura, Chartered 750 Commerce Plaza II 7400 West 110th St.
Overland Park, KS 66210 Telephone: (913) 661-9800, Ext. 119 Facsimile: (913) 661-9863 jim@sinizak-Iaw.com andrew@smizak-law.com OLATHE UNIFIED SCHOOL DISTRICT 233, SPRING HILL UNIFIED SCHOOL DISTRICT 230, BLUE VALLEY UNIFIED SCHOOL DISTRICT 229, and JOHNSON COUNTY COMMUNITY COLLEGE 20
ATTACHMENT A By: /4~1/.~
James G. Flaherty, #11177 ANDERSON & BYRD, LLP 216 S. Hickory- P.O. Box 17 Ottawa, Kansas 66067 Telephone: (785) 242--1234 Facsimile: (785) 242-1279 jflaherty@andersonbyrd.com Judy Jenkins Hitchye, #23300 7421 West 129th Street Overland Park, Kansas 66213 Telephone: (913) 319-8615 judy.jenkins@onegas.com KANSAS GAS SERVICE, A DIVISION OF ONE GAS, INC.
By: . /4 pe<<,,ije,,, S, 9'4/1#
- Jennifer S. Griffin, #17814 314 East High Street .
Jefferson City, MO 65101 Telephone: (573) 761-5006 Facsimile: (573) 893-5398 Grant Harse, #24666 2345 Grand Blvd., Suite 2200 Kansas City, MO 64108 Telephone: (816) 292-2000 Facsimile: (816) 292-2001 AMERICAN FUEL & PETROCHEMICAL MANUFACTURERS, MAGELLAN PIPELINE COMPANY, L.P., and PETROLEUM MARKETERS AND CONVENIENCE ASSOCIATION OF KANSAS, INC.
21
KCPL-KS Regulatory Assets & Liabilities Amortization Schedule (Docket No. 18-KCPE-480-RTS)
Per Rate Case Annual Unamortized Original Amortization Amortization Amortization Amortization Balance at Account Descriotion Adiustment # Vintal!e Balance Period Bel!in End Amount 12/31/2018 182329 Iatan 1 and Common RB-25, CS-111 1 2,855,631 47 Dec-10 Nov-57 60,758 2,364,503 2 631,250 44.9 Jan-13 Nov-57 14,059 546,896 2,911,399 182515 2011 Flood Exoense CS-110 924,928 10 Jan-13 Dec-22 92,493 369,971 182543 Customer Mieration CS-130 191125 5 Dec-18 Nov-23 38,225 191125 182546 La Cygne Depreciation Deferral RB-27, CS-113 2,957,141 25 Oct-15 Seo-40 118,286 2,572,713 182556 Rate Case Expense CS-80 203,212 5 Dec-18 Nov-23 40,642 203,212 TBD Merger Transition Costs CS-95 7,692,018 10 Dec-18 Nov-28 769,202 7,692,018 254000 Emission Allowance RB-55 (36,987 2321 22 Dec-10 Nov-32 (1 681,2381 (23,375 664) 254555 Wolf Creek Budaeted Plant CS-133 183,350! 5 Dec-18 Nov-23 116,670! (83,3501 254556 LaCv11ne Budgeted Plant C5-131 (1,985,865) 5 Dec-18 Nov-23 (397173) (1,985,865) 254556 LaCvl!ne Deoreciation Deferral CS-132 (11,666) 5 Dec-18 Nov-23 (2,333) (11,666) 254665 CIP - Cvber Tracker CS-88 1 12,182,3631 5 Dec-18 Nov-23 (436 4731 (2,182,363)
Attachment A Page 1 of 1
CERTIFICATE OF SERVICE 18-KCPE-480-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 _ _ 12_1_
1_31_2_0_18_ _ _ __
JAMES G. FLAHERTY, ATTORNEY MARTIN J. BREGMAN ANDERSON & BYRD, L.L.P. BREGMAN LAW OFFICE, L.L.C.
216 S HICKORY 311 PARKER CIRCLE PO BOX 17 LAWRENCE, KS 66049 OTTAWA, .KS 66067 mjb@mjbregmanlaw.com Fax: 785-242-1279 ~
jflaherty@andersonbyrd.com GLENDA CAFER, ATTORNEY TERRIPEMBERTON,ATTORNEY CAFER PEMBERTON LLC CAFER PEMBERTON LLC 3321 SW6TH ST
- 3321 SW6TH ST TOPEKA, KS 66606 TOPEKA, KS 66606 Fax: 785-233-3040 Fax: 785-233-3040 glenda@caferlaw.com terri@caferlaw.com THOMAS J. CONNORS, ATTORNEY AT LAW TODD E. LOVE, ATTORNEY 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 tj.connors@curb.kansas.gov t.love@curb.kansas.gov DAVID W. NICKEL, CONSUMER COUNSEL SHONDA RABB 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 d.nickel@curb.kansas.gov _ s.rabb@curb.kansas.gov DELLA SMITH ROBERT J. HACK, LEAD REGULATORY COUNSEL CITIZENS' UTILITY RATEPAYER BOARD KANSAS CITY POWER & LIGHT._COMPANY 1500 SW ARROWHEAD RD ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (64105 TOPEKA, ~S 66604 PO BOX 418679 Fax: 785-271-3116 KANSAS CITY>Mo 64141-9679 d.smith@curb.kansas.gov Fax: 816-556-2787 rob.hack@kcpl.com
CERTIFICATE OF SERVICE 18-KCPE-480-RTS DARRIN R. IVES, VICE PRESIDENT, REGULATORY RONALD A. KLOTE, DIRECTOR, REGULATORY AFFAIRS AFFAIRS KANSAS CITY POWER & LIGHT COMPANY KANSAS CITY POWER & LIGHT COMPANY ONE KANSAS CITY PLACE ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (64105 1200 MAIN, 19TH FLOOR.
PO BOX 418679 KANSAS CITY, MO 64105 KANSAS CITY, MO 64141-9679 Fax: 816-556-2110
.Fax: 816-556-2110 .ronald.klote@kcpl.com darrin.ives@kcpl.com TIM RUSH, DIR. REGULATORY AFFAIRS ROGER W. STEINER, CORPORATE COUNSEL
(
KANSAS CITY POWER & LIGHT COMPANY KANSAS CITY POWER & LIGHT COMPANY ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (64105 ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (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 tim.rush@kcpl.com roger.steiner@kcpl.coin ANTHONY WESTENKIRCHNER, SENIOR PARALEGAL BRIAN G. FEDOTIN, DEPUTY GENERAL COUNSEL KANSAS CITY POWER & LIGHT COMPANY KANSAS CORPORATION COMMISSION ONE KANSAS CITY PL, 1200 MAIN ST 19TH FLOOR (64105 1500 SW ARROWHEAD RD PO BOX 418679 TOPEKA, KS 66604 KANSAS CITY, MO 64141-9679 Fax: 785-271-3354 Fax: 816-556-2787 b.fedotin@kcc.ks.gov anthony.westenkirchner@kcpl.com I .
AMBER SMITH, CHIEF LITIGATION COUNSEL ROBERT VINCENT, LITIGATION COUNSEL KANSAS CORPORATION COMMISSION KANSAS CORPORATION COMMISSION 1500 SW ARROWHEAD RD 1500 SW ARROWHEAD RD
.. TOPEKA, KS 66604 TOPEKA, KS 66604 Fax: 785-271-3167 Fax: 785-271-3354 a.smith@kcc.ks.gov r. vincent@kcc.ks.gov JUDY JENKINS HITCHYE, MANAGING ATIORNEY JENNIFER .S. GRIFFIN KANSAS GAS SERVICE, A DIVISION OF ONE GAS, INC. LATHROP & GAGE, L.C.
7421W 129TH ST 314 East High Street OVERLAND PARK, KS 66213-2713 Jefferson City, MO 65101 Fax: 913-319-8622 Fax: 816-292-2001 judy.jenkins@onegas.com
- jgriffin@lathropgage.com GRANTHARSE ANDREW J. FRENCH, ATIORNEY AT LAW LATHROP & GAGE, LC. SMITHYMAN & ZAKOURA, CHTD.
2345 Grand Blvd. 7400W 110TH ST STE 750 Suite 2200 OVERLAND PARK, KS 66210-2362 Kansas City, MO 64108
- Fax: 913-661-9863 Fax:* 816-292-2001 andrew@smizak-law.com gharse@lathropgage.com
CERTIFICATE OF SERVICE 18-KCP E-480-RTS JAMES P. ZAKOURA, ATIORNEY CATHRYN J. DINGES, CORPORATE COUNSEL SMITHYMAN & ZAKOURA, CHTD. WESTAR ENERGY, INC.
7400W110TH STSTE750 818 S KANSAS AVE OVERLAND PARK, KS 66210-2362 PO BOX889 Fax: 913-661-9863 TOPEKA, KS 66601-0889 jim@smizak-law.com Fax: 785-575-8136 cathy.dinges@westarenergy.com DAVID L. WOODSMALL WOODSMALL LAW OFFICE 308 E HIGH ST STE 204 JEFFERSON CITY, MO 65101 Fax: 573-635-7523 david.woodsmall@woodsn:ialllaw.com ISi DeeAnn Shupe DeeAnn Shupe
\
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 ) Docket No. 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 Summm*y ................................................................................................................................... 4 Standards for a Reasonable Rate of Return ............................................................................................. 12 I(CC 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. Sonuna'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 of Debt ............................................................................................................................................. 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 Repmis 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 Accrnal 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 Alrnwhead 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 ofreturn that consists of the components in the 5 following table:
Westar Energy Rate of Return Proposed Rate of Return in Section 7 of Application Test Year Ended September 30, 2014 Updated to December 31, 2014 I i Weighted; Weight i Cost Cost i
'Long-term Debt 46.25%j 5.69%!. 2.63%!
I
'Common Equity 53.12%1 10.00%! 5.31%!
iPost 1970 ITC 0.63%1 7.99%: 0.05%!
7.99%i j Sources: Section 7 6
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% retum fot 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 of9.00% 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 Staffs range.
Range of Staff Proposed Rate of Return Assuming Staffs Proposed Capital Structure Return on Equityi 9. 00% 9.25%i 9.50%
Rate ofReturn' 7.46% 7.59%1 7.72%;
3 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 arn 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 Staffs revenue 19 requirement for Westar. This relationship is an approximation and assumes 5
Direct Testimony of Adam H. Gatewood Docket No. 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
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS Yield on Baa Utility Bonds Jan-05; 5.95:
Feb-05 5.76:
Mar-05 6.oo*
Apr-05 5,95!
May-05 5.88:
Jun-05 5.70.
Jul-05 5.80!
Aug-05 5.80 Seir05 5.83 Oct-05 6.08:
Nov-05: 6.19[
Dec-05 1 6.14)
Jan-06 6.06.
Average! 5.93; Nov-14f 4.75; Dec-14 4.70 Jan-15 i 4.39:
Feb-15i 4.44:
Mar-15! 4.51.
Apr-15: 4.51:
Mai-ls! , 4.91:
Average; 4.s8:
Source: Moody's !'
1 Yield on Baa Utility Bonds 10.00 9.00 8.00 7.00 6.00 4.00 2.00 1.00 0.00 .,., .,.,
,-. <- en en
'D
~ <'I <'l M 9 ~ 8 5: '.2 0 :i:§ ::i"" '
C\
9§ 0 9 ~ 0 0
" ~ ~ § § § §
- i
....." .....§ .=; 3
..., ..., ..:; ..., ~ ..., ..:; ..... ..., ..., ..., ..... ..., ....."'"
§ ::i ::i 2
3 Second, a 9.25% ROE provides a 500 basis point spread over the current market 4 cost of Westar's long-term debt. I observed recent trades of Westar bonds. Those 7
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 testimony, 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 cunent 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 of 2015.
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 rep01ted 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 of 2015.
8
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 this Docket are occuning 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 occuning in the same capital markets 4 enviromnent 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.
Credit Ratings
/<;;reat Plains Energy ' .Moody's S&P :Fitch Ratings
!Long-term Rating Baa2 'BBB+
,Outlook :Stable !Stable
- Westar Energy
!Long-term Rating !Baal BBB+ !BBB
!outlook !stable ;Stable :Positi~-e
- Sour_ce: SNL.com 7
8 Q. Please summarize Staff's cost of equity estimates.
9 A. The mid-point of my recommended range of 9.25% recogmzes that by most 10 measures capital costs have declined since Westar's last fully litigated rate case in 11 2005.
9
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS Summary of Staff's Cost of Equity Estimates Discounted Cash Flow Analysis Based on the Average of Short-Term Growth Forecasts
& Long-Term nGDP Forecasts Mean: .. 8.65%i Low 8.47%[
High[ 8.84%:
Internal Rate of Return Analysis Using Short-Te1m Growth BPS & Long-Term nGDP Forecast i I
- Mean' 8.53%/
Low 7.18%\
High! 10.01%[
i Capital Asset Pricing Model Forecasted Data: 6.64%[
Historic Datai 9.40%f Changes in Bond Yields Since Order in 05-WSEE-981-RTS Docket i Allowed Return on Equity Granted in 981 Docket', 10.00%\
Decrease in Yield on Moody's :Saa Uility Bonds j 1.35%!
Staff RecommendaHon: 9.25%
Indicated Range' 9.00% ; 9.50%
1 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 three 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 occuned-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.
i i Summary ofWestar's Cost of Equity Estimates
& Growth Rates i
Range of
! Methodology Output Discussion
'SingleStageDCF I 9.47% 9.52%1 /Mr. Somma's DCF analysis relies on a single stage DCF using 3 to 5 yearforecasts of
'imnual earnings growth rate~. For his proxy group the average ear_nings growth rate _is ts.86%.
- i ;
i ' . . . . i .
'cAPM .. : I0.86% 1L76Jiol. . !Mr, Sonuna'§. C:Af'l\1_afllllysjs i~. ~a_se<I.<>n_hJ~.a~§llll1R.1i<ln th~t th_e "llla_r}fet" or S<%P590.
Jn<lt1,t '!".i.11 rt1!t1In 1:3)'.jo/ci allll_ually: J:Iis a.ria_Iys is ~~~ll!lles !P.,3,(tl1e §.8.::P.?OQ .
f\vjll re!!Jize imnual earnings grml'.th greater Iha.~ 11.00%
- : I i
- Risk Premiwn 10.33% 10.38% !Mr. §_onuna calc~atedari_s!f3ire111illltl_ba~edonthe differe_nce ~etwet1n the returns .
- ' granted
. . . .by. .state
. . .! commissions and the prevailing1 interest
................................. rates. '
8 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 suppo1i 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 l have observed is that Kansas utilities continue to issue long-tenn 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, preferred 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.
C?mponents of an Allowed Rate of Return Weighted i ! .
Debt A : Ratlo of Debt Weighted A\erage Capital: \erage ! x Ca ital Cost of Debt Interest Rate p Allowed Equity :Ratio ofEquity WeightedA,erage Return on Capital: 'x ! Capital . = : Cost of Equity Equity I I Sum Equals Allowed Rate of Return for the Utility 16 17 The cost of debt generally relies on a contractual agreement with the investor, 12
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS 1 making its cost relatively easy to detennine 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 cam1ot 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 ailllounced 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 miiculate 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 imp01iant 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 Couti 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 Cami's decision in Bluefield 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 Bluefield 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. 1O-KCPE-415-RTS; November 22, 201 O; 37-3 8.
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 I) 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 Blue.field 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 Blue.field, 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 Blue.field.
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 corresponding 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 irnpo1iant to this case to determine the various permissible ways in which any rate base on which the return is computed might be arrived at. For we are of the view that the end result in this case cannot be condemned under the Act as unjust and unreasonable 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 know 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 Proxv Group 5 Q How did you estimate Westar's cost of equity?
6 A To estimate Westar's cost of equity, I perfonned 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 industry 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 impotiant 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.
Credit Ratings
! Great Plains Energy Moody's S&P Fitch Ratings
- Long-term Rating Baal ;BBB+
Outlook Stable ;_Stabl_e
!Westar Energy
/Long-term Rating Baal [BBB+ BBB
- ,Outlook Stable 'Stable ,Positive Source
- SNL.com 12 13 I selected electric utilities with credit ratings one notch either side of Westar' s rating.
14 Credit ratings are a recognized broad indicator of a utility's financial health, financial 15 risk, and business risk. Selecting those electric utilities with credit ratings very close 16 to Westar's enables me to observe investors' required retum for that level of risk.
17 The following table shows the entire scope of credit ratings designations set by S&P 18 and Moody's:
18
Direct Testimonv of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS Credit Rating Range for Proxy Selection
- i. I.
S&P i Moody's \
AAA l Aaa M+ Aal M Aa2 M- Aa3 A+ Al A A2 Proxy A- A3 i Selection BBB+ Baal :Westar Long-term Rating I
Range BBB Baa2 i i
BBB- Baa3 I i BB+ Bal lI BB Ba2 BB- Ba3 i B+ Bl B B2 B- B3 j CCC+ Caal CCC Caa2 CCC- Caa3 cc Ca C
D D 1
2 The electric utilities followed by Value-Line fall in the range of AA-/Aa3 3 to BBB-/Baa3. Nanowing 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 Fomih, 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 sotmd 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 anive 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 cunent information from the 4 capital markets via cmTent stock prices and accurate data that investors use to 5 establish their discount rate. The market based info1mation 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 anive 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 BmT Williams' 1938 text 3 The Theory of Investment Value. These two authors expressed the DCF model in 4 modern 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 ofreturn is risk sensitive and sensitive 10 to the retmns 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 ofretmn 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 riskier 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 referred to as the Gordon Growth Model, which is a model that values the 19 present value of a stream of 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 cunent 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 investments, 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 knowing the stock's dividend yield 12 and the annual dividend growth rate expected by investors. That form of the 13 equation is:
D0 (1 + g)
Ke= Po +g 14 This equation is frequently written out as:
15 Req 'd Rate ofReturn = (Current Annual Dividend/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:
.)
- 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 con-esponds 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 of 2.63%.
24
Direct Testimony of Adam H. Gatewood Docket No. 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 cmTent 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 rep01is for 7 each of the proxy companies are attached as Schedule AHG-5. I obtained the 8 stock prices for the dividend yields from Y ahooFinance. 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 cunent 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 tln*ough 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 tln*ee to five-year ammal 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 grovvth rate continues in perpetuity, well beyond the 20 tln*ee 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-tenn perspective of potential growth, investors rely on forecasts of the 2 broad economy. There are sources for long-te1m 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-te1m 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 pmiies made it 21 clear that long-term estimates of nGDP m*e 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 PL07-2-000.
27
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 long-tenn 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 incol1'ect growth estimate will lead to inconectly 8 valuing an asset. Academic research supports has shown that nGDP growth 9 forecasts are an impo1tant 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 Dete1mining the Value of Any 13 Asset, 2nd Edition and Damodaran on Valuation: Secmity 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 grmv 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 Opinion No. 531; June 19, 2014; 147 FERC 61,234; para 36.
28
Direct Testimony of Adam H. Gatewood Docket No. 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. Ce1iainly 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 Arnott 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 growih 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 DocketNo. 15-WSEE-115-RTS nuo il/l!'Orim1/ (()//Cr'JIIS ,,,aytd ii key role ill Ille /111/1111arkel or tile l99Us.
13otfi represc11tfwulamcnlol /7mus in logic. Ho//, arc dc111011slmlily 1111/r11c.
First, n1a11y im.11':,tors /Jdir*I'Cd /Ital eami11gs could grow fas/a than tile 111c1croeco110111.11. l11 fhcl, e11mi11gs 11111st grmu slowl'I' llit111 CDP l1crn11sc the grmui/14cxisli11g e11/l'rpris1*s co11tri/1ufc*s 011/y parl tf CDP grmut/1; the role 0/1'/I f l'f'J)l't'/11'11 rial Cl1f Ji[a/ isl/I, //,c* C/'l'tl / io11 u( /ICW l'llf erprises, is a key driver of CDP grow/Ii, 1111d it docs 110/ co11trilJ11/c lo //,c growi/1 i11 £'£1/'lli11gs lll1d tfioid1*11tfs ,!f cxisli11g c11/c1priscs. J)11ri11g Ille* 20/lt cc11/ 11ry, grow/11 iJI s/ock prices 1111d dividends mis 2 1wrn'11/ fess t/11m 1111dl'rlyi11g 11111C1H'Co110111ic xrowi/1. Scco,rd, 1111111y i11vcstors /Jdi<*vcd Iha/ stock buybacks would pa111it t'l//'lliligs lo srmu/i1s/cr !lt1111 CDP Tlic iJIIJIOl't1111/ mclri( is )I()/ the zio/111111'
,!f ll/ly/1/lcks, /iouwv,*r, !JIii 11d huylwcks stock b11yl1acks less 11cw shnrc issu1111ce, w/Jc//,er i11 exist i11g 1*11/crprise::,; or lllro11sl1 I POs. Wt' 1fr11m11s/ mlc, 11si11g Jwo 11/r'f/Jodologics, lllfll tl11ri11g lite 20//1 ce11/ 11ry, news/Jan* iss11m1ce in 1111111y 1111tio11::; 11/11/os/ ahu11ys cxn*,*dcd slock in,y!Jacks l,y 011 avc1*11xe of 2 percent or 11wrc o year.
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 l4 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 Docket No. 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 pe,petuity. Granted, it is almost a truism that aggregate earnings must 11 grow at the same pace as the overall economy in the ve1y 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/ltcmra) 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 asce1iain 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 DockctNo. 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 DocketNo. 15-WSEE-115-RTS Cash Flow Westar 15-WSEE-115-RTS
' Stall's
'l - Discounted
~ - . i -- . -- -
2 3 4 5 6 I
Dividend Yield Grov,th Cost ofTh]uity Low High Rate Low High iA!lete Inc :ALE 3.88%1 H_S'Yo .. 5.36%i 9.23%! 9.81% 1
- iAlli~t Energy Corp L.NT 3.61 o/~ 1 3.90%: 5.12%; 8.72%; 9.02%!
lAmeren Corp iAEE 4.03%1 4.38%' 5.20% 9.23%: 9.58%1 i American Electric P\\T Co i\EP 3.86%[ 4.17%: 4,79% 8.§5Jto' 8.96%1
!A~;ia Corp * * 'AVA 4.03%[ 4.41%' U9% 9.22% 9.60%1
- CMS Ene~gy Corp ,CMS 3.40%1 3.74%; 5.23% 8.63%i 8.97%1 iC:.onsolidated Edisol} Inc El) 4.26%[ 4.5~%' 3.44o/o 7.70% 8.02%1
- Dominion Res9urces Inc D 3.68%i 4,00_%1 5,49%. 9.16% 9A2%l iDuke Energy Corp New :DUK 4.20%1 4.56%; 4.61% 8.8lo/.i 9.17%1
!Edison International lEIX 2.69%i ~.03%; 3.72%. 6.41'i'o 6.75%;
!:l~l Paso Electric Co iEE 3.12%1 3.56%1 4 ..82%. 7.94o/o 8.37o/oi iEmpire District Electric Co 1
!EDE 4:251%1 4.78%! 4.36%' 8.. 64% 9.14%:
Great.Plains Energy Inc !GXP 3.81%) 4.16% 5.29%/ 9.10%i 9.45%j lIDACORP Inc !IDA HWYol 3.36o/oi 3.69%i 6.73%: 7.05%!
- NorthWestern Corp. .
- NWE 3.66%[ 4.01%i 4.94%1 8.60%' 8.95%!
IOGE Energy Corp :cxrn 3.29%1 3.55% 4.i9%; 7.48%i 7.74%!
IPacific Gas and Electric Co. :Pc.G ),50o/ol 3.77%' . . .?,26o/oi 8.75%1
!Pinna;leWest c;;pita!Corp iPN\V 3,90%1 4.37% 4.47%: 8.31%; 8.84%i
!Portl~d General Electri; Co. iPOR 3.26%) 3.61%! 4.88%: 8.13%: 8.48%!
I1ECO Energy )E 4.72%1 5.24%1 5.64%; 10.36%! 10.88%!
J w~.s.t.rr!,11~rgy_Inc *WB .3.79%i 4.24%: 4,29'l"oL 8.Q~o/o *8.53%i i Xcel Energy Inc !XEL 3.78%1 4.09%: 4.54%1 8.32%1 8.63%1 i Average: 3.72% 1 4.09%; 4.75% 8.47%1 8.84%1
- .... --~ er*
Average oflow&High 6.41%:
M,.?'Yo 10.88%1 1*K~C proxy gr_oup Pricing March
- .May;
- I 2: 2016 fore casted dividend/ observed high stock price I 3: 2016 forecastcd divid~nd / ob;~rv~d l~w sto~k price 4 *gro\Vth.rate, _ave~age of long-run and shorJ:run foreca;;t~d grm,th 5 *Min Dividen_d Yield+ Gro,,1h Rate 6: Max Dividend Yield+ Grav.th Rate N_o observatios \\ere climillat~d as i]logical or outliers. The test for low outliers is yield on Baa utHity bonds
. plus 199.ba;;is points (4.60% +1.00%== 5,60%) '
I 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.
l I j Summary of G_rowth Rates I
Value:I,ine Historic Data Forecasted Earnings Growth Rates 15-WSEE-115-R'IS DPS Growth EPS Gro\\th Val~e Li~e !
10 Year f 5 Year 10 Year I 5 Year , DPS I EPS !BES ; FactSet
!Allele Inc !ALE 0.00%! 2.00%: 7.00%i 1.00%1 4.00%[ 7.00%[ 6.00%1 6.00%[
!Alliant Energy Corp :LNT 3.50%; 6.50%) 8.00%/ 6.50%! 4.50%/ 6.00%[ 5,45%[ 6.10%!
!Alneren Corp - - !AEE :450%1 -9.00%! -2.50%! -4.00%! 2.00%1 5.00%1 5.85%! 7.22%!
. IAnlerican_Electric PwrCo. ;Al:!' -l.50%i 4.00%! 0,50%j 1.50%J _5,0_()%! 5.50%1 5.10%; 5.oo%J
!Avista Corp !A,VA 2.sgo;,! l!'.50o/ol 7.50'Y,i 6.50%; 4.00%! 7.00_%! s:oo%i 0.00%1
- GM$.)~ne[gy_C:orp ;<::Iv!§_ 0.00%1 _23.50%i 0.00%! 12.00o/o! 6.50%1 5.50%1 6.73%! 6.00%1
- Collsolidates! Edison Inc. '.ED_ i.O
- <i%l J.OOo/oi 3,~0o/oj .. 2.50%' 2,50.o/ol foor,i 2.48o/ol 2.00%1 iD<nninioll :Rcs_ourccs Inc :p__ - 5.59_%! 7.0Q_o/ol 3.QO%i 2,50o/oj 7.50%! 8.00%: 5.89o/ol 5.90%1 LDuke Energy Corp '.DUK _0.00%\ 2.50o/oi 0.00%1 3.50%/ 2.50%! 5.00%\ 4.4_9%i. 5.00o/oi
- Edison International ,EIX O.OO%i 2.50%1 10.00%1 4.50%! 10.00%1 3.00%! 0.70%1 5,SO'Yoi i El Paso Electric Co [EE 0.00%! 0.00%i 13.50%[ 6.50%i 5.00%l 3.50%1 7.00%1 O.OO%J
- Empire Distr. Electric
- EDE -2.50%1 -4.50%j 2.50%, 5.00%: 3.00%1 3.00%1 5.00%i 5.00%!
- Great Plains E~e~gy Inc i GXP -6.50%[ -1:1.50'.lfo! -3.50%i -2.00%i
' 5.50%! 5.00%1 6.80%i 6.80%!
! Idacorp, Inc -
- Northwestern Corp
\QQE _Et1_ergy Corp _.
- m
- IDA OGE O.OO%i O,OO%i
- I.Q0%)
5.50%1 3.00%'.
3.00%i 9.00%!
0.00%1 9.50%!
10.00o/oi 8.00%)
7.50%!
6.00%!
6.50%i 10.00%1 1.00%[
6.50%!
3.00_o/oi 4.00%j 5.00%1 4.00%\
4.00%:
5.00%;
5.00%i IP~cific Gas 8:Electdc Co iF'C.G 0.00%; 3.00%1 14.50%[ -5.00%1 2.50%! 8.50%j 4.71%i 5.20%1 iPh1nac_le "Y_estCapital Corp :P_N\\' _ 3,50%! 3.00%: 3.50%[ 8.00o/~I 3.50o/o: 1,00%: 4.70%! 5.00'loi iPortland General Electric Co ,POR 0.00%! 2.50%! 0.00%1 3.00%[ 6.00%i 6.00%i 4.72%! 5.40%1 t '!ECO Energy - - Frn -1._50o/o[ 2.00%[ i.~0%/ 0.00%1 2.00%1 6.00%! 9.20%i 5.50%1 i Westar Energy Inc iwiz 3.50%i 3.50%1 6.50%1 9.00%[ 3.00%1 6.00%! 3.40%1 3jo%i
- Xcel Energy Inc iXEL 2.50%: 3.50%/ 7.00%i 6.00%i 6.00%[ 4.50%1 4.58%1 5.00%/
lMean
1.12%! 3.02%t 5,61%j 4.40%1 4.89%! 5.09%[ 5.04%1 5.19%:
I 1
i ' i Min -6.50%[_ 7 12.50o/o[ -3.50%l -5.00%[ 2.QO%[ 1.00%i 0.70%: 2.00%i
!M~ 9.50%1. 23.50'.% 1450%!
. .! 12,00%; ' 10.00%! 850%! 9.20%1 722% 1 7
8 Q What are your observations of the short-run growth forecasts?
9 A The average of the short-rnn growth forecasts for the proxy group is 5.12% with a 12 For each proxy company, I gathered four short-run, 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 of 2.50% 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 Infonnation 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 EIA 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 DocketNo. 15-WSEE-115-RTS 1 (0MB) 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 te1ms 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 awrage annual econo1nir growth projections, 2012--10 Average annual percentage growth rates Projedion 2012-2015 2012-2025 2025-2040 2012-2040 AE02014 (Referera:e case) 2.6 2.5 24 2.4
-~ ""
AE02013 (Reference case) 2.6 2.6 24 2.5 IHSGI (May 2013} 2.6 2.5 24 2.5 0MB (January 2014)' 2.7 2.6 CBO (February 2014)' 2.6 25 IN FORUM (November 2013) 2.4 26 2.3 2.4 Social Se<:urity Administration (August 2013) 3.0 27 2.2 2.4 IEA (2013i . . . - . .. 2.6 2.8 2.4 ExxonMobil 2.5 2.2 2.4
_OEG (January 2013} 2.7 27 2.5 2.6 n = not reported C( not applicab]t!.
'OMO and CBO projections end In 2024, and growth rates cited are for 2012-24. AEO projeclicr.s end in 2040.
'IEA pub!ishesU.S. grov,1h rates fer cutain Intervals: 2011-15 growth is 2.6"%, 2011-20 growth is 2 8%, and 2011-35 grcwlh is 2A%.
CP-2 U.S. Energy Information Adminl,tralion I Annual Engrgy 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 DocketNo. 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 in Schedule AHG-9. The following table 4 summarizes the results of the IRR. Recognizing that the sho1i-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.
Internal Rate of Return I
!Allete Inc 8.96%,
IA1Iiant_E11ergy C<lrp 8.45% .
IAmeren Corp 8.98%,
f American Electric Pwr Co 8.66%:
8099%1
- !itsJ~~~: Corp 1* 8 27%:
- iConsolidated Edison Inc s:73%i
!Dominion Res.ources Inc 8.64%l
- Duke Energy Corp New 9.0i%i
.!Ediso11 I11te_rnatio11al z.!.8%!
iEI Paso Electric Co 7.91%:
iJ::mpjre District Electric Co 9.10%1
! Great Plains Energy Inc 8.75%!
iIDACORP Inc 7.52%;
- NorthWestern C
- CJrp. 8.SQ'Yoi iQQE Elnergy Corp 7.87%'
iPacific Gas and Electric Co. 8.35%!
- Pinnacle West CaJ)ital Corp i 8.69%
1 iPortl~d Genenil Elect~ic Co. ! 8.03%:
- 1ECO Energy 10.01%
lWest.or Ilnergy Inc 8.52%,
l Xcel Energy Inc 8.50%
Mean! 8.53%,
Min! 7.18%
Max[ 10.01%
8 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 cun-ent 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 of risk-free securities often calculated as Rm- Rf 12 Beta= volatility of the security's or po1ifolio'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 sho1i 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 retmn earned by the utility's stock 27 relative to the volatility of the returns earned by the broader equity market. The 13 The theoretical suppmi for the CAPM is the work done by Hany Markowitz ("Pmifolio Selection,"
Jomnal 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 DocketNo. 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 risk 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.
Beta Coefficients of Proxy Grou_p
!t\llete Inc :ALE
.- ~. 0.80j iAlliant Energy Corp LNT 0.801 iAmere~ Corp fAEE 0.75!
[American_Electric P\\r Co iAEP 1AVA 0,79!
- A,ista Corp o.soi JCMS Energy Corp ;CMS 0.75[
lConsolidated lcdison Inc IED 0.601
!i-Dominion
-- *- Resources. Inc-
'D 0,70[
I
, Duke Energy Corp New ,DUK 0.601 i Edison International iEIX 0.75!
JEl f'.aso E!i<>t~ic .~~. 1EE ojoJ J Empire District Electric Co [EDE Q.70!
iGreat Plains Energy Inc GXP 0.85i iIDAC()RP Inc iJDA o.so!
I
,NorthWestern Corp. NWE 0:10!.
IOGE Energy Cof]) - 'OGE O.~Oi
!Pacific Gas and Electric Co. PCG 0.65!
1 Pinn_acle West C~pital C:<lrJJ iPNW : -- 0.70l
- l'ortlan~ General Electric_Co. ,POR
- o.soi i1ECO Energy IIB o.s5i iWestar Energy Inc !WR 0.75!
iXcel Energy Inc IXEL 0.65i 0.74!
- Source
- Value-Line Investment Survey 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 Docket No. 15-WSEE-115-RTS 1 anived at those forecasted returns. 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 Capital Market Return Assumptions are used v1idely 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. Tllese 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: whicll 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; h!.tJ?s://am.ipmorgan.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 1s essentially the 2 additional return necessary to induce investors to take 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 asce1iain 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%.
Capifal Asset Pricing Model --Forecasted RiskPremium Using Forecasted
. Market
.. . Returns
. &. Treasury
. !Bond Yields Proxy Group & Westar Beta I)\ForecastedReturns on Common Stocks 7.60%\
2)/Forecasted Total Return on 10 Year T-Bonds 4.41%[
i
- 3) Resulting Ris~ Premium 3.19%:
- 4) iBeta Coefficient l -- -
xi 0.75 i 5): Risk.Premium 2.39%1 6)!Forecasted Yield on lQYear T-Bonds +: 4.25%1
- 7) Forecasted Cost of Equity 6.64%:
- 1) !Forecasted 10 to 15 Year Annual Return Arithmetic return on stocks for large companies
- ** ***-* *+
!by J.P. Morgan Asset Management 2015 Edition.
- 2) \Forecasted 10. to 15 Year Annual Return Arithmetic return on intermediate term
!U.S. Bonds by J.P. Morgan Asset Management 2015 Edition:
3)tResultingriskpre~i~1 (1-2) .. . . .
4)/Beta coefficient of0.75 for the Proxy Group and Westar (Reported by Value-Line) l - *
- 5)/row3 xrow4 = a%et specific risk premium 6)!Forec~t~d Yield on 10 y~ar U.s: T~easu~ Bonds Forecasted by lJ.P. Morgan Asset Management 2015 Edition; Fixed Income Assumptions; Exhibit 2; p.56 I
- 7) Forecasted cost of equity capital row 5 + row 6 ! .
Sources::
J :p. Morgan Asset_Management, I AJng-term Capital Market Return Asstm1ptions 1 2015 Edition; J.P. Morgan A5set Management.
www.jpmorganinstitutional com/pages/jpmorgan/am/ia/research_ and_publica!ions/long-tenn_ capitalmarket i i . '
9 43
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 of 2015.
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.phi1ade1phiafed.org/research-and-data/rea1-time-center/survey-of-professiona1-forecasters/2015/survg 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 Capital Asset Pricing Mo~el -- Historic Risk Premium Based on Historic Risk Premiums from 1926 to 2014 Proxy Group & Westar I '
i Beta I I
- 1) !Total Returns on Common Stocks 12.10%1
- 2) ITotal Return on Government Bonds 6.40%!
, I
- 3) i Resulting Risk Premium
- 5.70%1 i
4); Beta Coefficient Xj 0.75 i
- 5) Risk Premium 4}8%1 I
- 6) iYield on Government Bonds +i,, 5.12%!
- 7) iForecasted Cost of Equity 9.40%1' I
- I
l)iHistoric returns on common stocks 1926-20141 I
- 2) !Historic returns on Long-term Government Bonds 1926-2014 3)1Resulting risk premium (1-2) 4)! Beta coefficient of0.75 for the Proxy Group and Westar (Reported by Value-Linc)
- 5) [row 3 x row 4 asset specific risk premium !' '
- 6) 1 Historic Year-End Yield on Long~ term Government Bonds 1926-2014
- 7) iForecasted cost of equity capital row 5 + row 6, j Sources:
lIbbotson SBBI: 2015 Classic Yearbook & Value-Line Investment Survey 1
2 Keep in mind that, in relying on historic data, we are assuming that certain 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 DocketNo. 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 Adiusted ROE Recommendation Range Weiflht 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% 2.58% 2.60%
10.03% 10.30%
Issuance Costs 0.12% 0.12%
Adjusted ROE 10.15% 10.42%
7 8 His cost of capital study anives at a range of 10.00% to 10.30%. 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 cunent and prospective 14 economy lowers the result closer to Staffs DCF analysis. Mr. Som.ma'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 of 7.60 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. Tln*oughout his testimony, he refers 4 to securities analysts' three to five year eamings growth forecasts as "long-te1m 5 forecasts." His methodology is contrary to the fundamentals of the DCF model 6 which views growth prospects well beyond Mr. Solllilla'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. Solllilla 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 tln*ee 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. Solllilla's 19 position that market participants use a tln*ee 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 Somma Direct 15-WSEE-115-RTS; p43; line 1.
50
Direct Testimony of Adam H. Gatewood Docket No. 15-WSEE-115-RTS Annual Growth Rates Contained in Mr. Somma's DCF Analysis Growth i
[Westar Energy, Inc. . 4.22%1
- Ameren Corp 7.08%j
/Allete Inc 6.00%!
/Avista Corp 4.75%1 IGreat Plains Energy Inc 5.24%!
iIdaCorp Inc
- excluded i IAlliant Energy Corp 5.45%j i NorthWestern Corp 6.87%!
I iOGE Energy Corp 5.68%1 IPNM Resources Inc 8.14%1
!Pinnacle West Capital 4.48%1 i Portland General Electric Co 7.23%!
i TECO Energy 5.17%!
tMean 5.86%1
\Median 5.56%!
i i
!Source: Response to KCC DR #85 1 i 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 cunent 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 cmTent, 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. Somma'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. Somma'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 comp01i 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; Mornningstar; p.40.
53
Direct Testimonv of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS 1 co1Toborating 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 growih 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 zeroing 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. S01TI1na's analysis the forecasted growth rate for ExxonMobile is negative 16 for the next three to five years. That is not surprising 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 Exxoru\1obile to collapse; it has 55
Direct Testimony of Adam H. Gatewood DocketNo. 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 pmiicipants likely recognize that 10 Exxoru\1obile'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 sho1icomings 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. Som.ma'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 ~* Som.ma'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 cmrent 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. Sornma'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 performing a DCF analysis on all of the electric utilities, 6 without attempting to select a proxy group of comp1;trable 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 anive 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 imp01iant 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 nonn 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 fmdings 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 suppoli inclusion of flotation costs in its cost of equity because 18 Westar has not attempted to quantify the amount, if any, of umecovered 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
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS Quantification of Westar's Proposedtiotation Cost Adjustment I
/Total Rate Base (Application Section 3) *$ 5,062,804,912 i iEquity Ratio of Capital Structure 53%;
i' Equity Financed R:.c1te Base .$ 2,683,286,603 j l
iFlotation Cost 0.12%.
/Tax Gross Up Factor 0.6667
. !Pretax Flotation Cost Collected in Rev Reg 0.18%
!Annual Flotation Cost Charged to Westar Consumers $ 4,829,674 '
i 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-.fany of the predictable patlerns that have been discovered may simply be the result of data mining. The ease of experimentingwith financial databanks of almost every conceivable dimension makes it quite likely that investigators will find some seemingly significant but wholl)' 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 pauern out of most data sets. Moreover, the published literature is likely to be biased in favor of reporting such results.
Significant eflccts are likely to be published in professional journals while negative results, or boring confirmations of previous findings. are 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 al a symposium about a decade ago between Robert Shiller, an economist who is sympathetic LO 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, I 992). After Shiller stressed the importance of inefficiencies in lhe pricing of stocks, Roll responded as follows:
I have personally tried Lo invest money, my cliem's money and my own, in every single anomaly and predictive device that academics have dreamed up .... I have attempted lo exploit the so-called year-end anomalies and a whole variety of strategies supposedly documented by academic research. And I have yet lo mahe a niche! 011 any of these supposed 111arl1el inefficiencies ... a true market ine.fficiency ought lo 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 lo 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. Staffs 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 retum is evaluated in each general rate case and, given the 16 cunent 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 Conunission 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.
I _I P_ro _Forma Capital_ Stru_cture_
Test Year Ended September 30, 2014 i_ __ I Used In the ROR i Septembef30, 2014'. December 3{ 2014 j Pro Forma Pro _Forma .-- I I Totals -Adjustrrents . l Adiuslmenis I December 31, 2014 , Ratio Long:terrri__[l_ebt i $ 3,215,356,038: 49.29%i $ 183,066 i $ (125,000,000)\ $ 3,090,539,104 ! 46.2_5%'
GorroJOn Equity i$ 3,264,878,394_; - 50.05%! $ 29,~77,61<i l $ - 254,489,857 I $ _ 3,S49,i45,861 / 53.1_2%'
Post 1970 ITC I$ 42,801,587' 0.66°-il $ (782,217)1 $ - I$ 42,019,370 i 0.63%1 I$ 6,523,036,019 ! $ 29,378,459 i $ 129,489,857 I $ 6,681,904,335 I i i I Sourc_e: Section 7i_ l 8
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. Staffis using Westar's capital structure as 15 shown in Section 7 ofWestar's Application.
64
Direct Testimony of Adam H. Gatewood DocketNo. 15-WSEE-115-RTS Equity Ratio 50.00% .,__ _ __
49.00% .,__ _ __
48.00% + - - - - -
46.00%
45.00%
44.00%
2010 2011 2012 2013 2014 1
2 2010 2011 2012 2013 2014 Debt Ratio 53.46% 49.46% 51.11% 50.76%i 50.60%
Equity Ratio 46.54% 50.54% 48.89%; 49.24%: 49.40%
3 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 of long-term debt 7 of 5.687%.
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 refened 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 Docket No. 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 N01ih 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 trust 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 anive at an estimate for the annual accrual.
16
- Decommissioning cost estimate set in Phase-One (15-W CNE-093-17 GIE) 18
- Decommissioning timing set in Phase-One (15-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
- Cunent 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 DocketNo. 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. Fo1iunately, 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 correctly 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 current interest rate on the 30 Year Treasury Bonds for the fixed income 67
Direct Testimony of Adam H. Gatewood DocketNo. 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 ofWestar'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 sho1i-terrn fixed income securities are higher than Westar's forecast.
Comparison of Forecasted Returns I ,
I i J.P. Morgan Westar* Forecasted** ;
/Large Capitalization Equities 11.40%1 7.60%[
ISmall Capitalization Equities 10.27%!
I 8.81%i
\International Equities 7.65%t 8.10%j
!Core Bonds (Corporates) 4.89%! 4.95%!
[High Yield Bonds 7.63%1 6.40%1 iReal Estate
- 7.73%/ 8.17%:
iCash & Equivalents 0.98%i 2.00%i I
i*As filed in the testimony of Susan North (SMN-1)
! 1 I
- Asset class forecasts of 10 to 15 year annual returns; J Long-term Capital Market Return Assumptions, !
- 2015 Edition (U.S.); J.P. Morgan Asset Management.
13 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 infonnation 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. 24 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 malting to Exhibit SMN-1?
12 A My recommendation is to change the expected returns 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 umealized 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 SMN-1 are substantially higher than its experience since 1985.
15 Q Does this conclude your testimony?
16 A Yes.
25 In response 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 trust 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
Schedule AHG-1 15-WSEE-115-RTS
),foody's Public Utility Bend D:tt:t Moody's Public L'tllity Bend Dau Moody's Public: Utility Borid D:i.1:1 '.\foody's Public t:tility Bond D::e:i. ).foody's Public Utility Bond Om Moody's Public: l:tlity Bond Dau Moody's P.Jblic Utility Bond Data B~ A Bu A Bu A Bu A Bu A Bu A Bu A
!1111-19 6,89 6.35 J:m-24 6.i3 6.02 J:m-29 :5.4S 5.05 Jm-34 8.S6 6.56 J:!ll-39 4.66 3.6S J:m-44 3.54 2.99 Jan-49 3.42 2.99 Feb-19 6.91 6.39 Feb-24 6.6' 6.00 Feb-29 5.51 5.10 Feb-34 7.SS 5.73 Feb-39 4.59 3.59 Feb-44 3.53 2.99 Feb-49 3.40 ~99
).far-l9 6.91 6.41 ).far-24 6.60 S.97 ?i.far-29 5.62 5.14 )..fu.J4 7.5S 5.66 )..far-39 4.53 3.54 3.52 2.97 1-br-49 3.36 2.97 Apr-19 6.SS 6.18 Apr-24 6.55 S.94 Apr*29 5.69 5.14 Apr-34 7.18 5.44 Apr-39 4.62 3.55 3.53 199 Apr-49 3.31 2.96
)..uy-19 6.&4 6.27 ),fay-24 6.42 5.91 ).1'.:iy-29 5.66 5.14 11ay-34 7.17 S.39 M:i.y-J9 4.50 3.50 3.53 299 May-49 330 2.95 JIJ!l-19 6.S4 6.19 Jun-24 6.32 S.19 Jun-29 5.72 5.23 Jun-3:4 7.20 5.40 JU11-39 4.41 3.47 3.53 299 Jun-49 3.28 2.94 Jcl-19 6.79 6.16 Jul-24 6.23 5.6S Jul-29 S.79 5,24 Jul-34 7.36 5.29 JuJ-39 4.39 3.43 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.S9 5.30 Aui;-34 7.68 5.43 Aug-39 4.39 3.41 Au:;-44 3.51 2.94 Aug-49 3.25 2.S6 Scp-19 6.94 6.4-! Sep-24 6.24 S.71 Sep-29 5.92 5.38 Sep-34 7.62 5.56 Sep-39 4.64 3.71 Sep-44 3.51 293 Sep-49 3.22 2.SS Oct-19 7.0! 6.41 Oet-24 6.21 5.65 Oct-29 5.91 5.34 Oct-34 7.38 5.40 Oet-39 4.4S 3.58 Oa-44 3.51 2.94 Oc:t-49 3.19 2.83 Nov-19 7.08 6.67 Nov<!.4 6.24 5.62 Nov-29 6.00 5.29 Nov-34 7.21 5.3S ::S-ov-39 4.38 3.41 Nov-44 3.53 2.96 Xo.......49 3.17 2.Sl Dcc-19 7.25 6.79 Dee-24 6.t3 5.63 Dee-29 S.96 5.23 Dec-34 7.03 5.36 Dec-39 4.36 3.38 Do,-44 3.54 2.97 Dec:-49 3.16 2.7S J::n-20 7.30 6.S5 fan-25 6.12 5.61 fan-30 5.92 5.26 J:i.n-35 6.60 5.18 fan-40 4.30 3.34 JMl-45 3.50 2.99 J:tn-50 3.IS 2.76 Fcl>-20 7.4S 7.03 Feb-25 6.08 :5.52 Feb-30 S.93 5.29 Feb-JS 6.ZO 4.96 Fcb-40 4.23 3.35 Fcl>-,.fay-31 6.36 4.$4 Mly-36 4.76 4.14 M:ty-41 3.SS 3.0S M:;-*46 3.02 2.69 May-SJ JJS 3.13 Jun-21 S.62 7,6' Jun-26 5.61 5.ll Jun-31 6.60 ,(Si Jun-36 4.72 4.12 Jun-fl 3.S3 3.03 Jun-46 3,04 2.70 Jun-51 3.45 3.21 Jul-21 S.'4 7.72 Jul-26 5.61 5.13 Jcl-31 6.47 4.83 Jul-36 4.62 4.07 Jcl-41 3.82 3.00 Jul-46 3.03 2.69 Jul-SJ 3.49 3.26 Aus-21 S.66 7.67 Aui;-26 S.62 5.15 Au;;-31 6.60 4.Sl Aug-36 4.59 4.06 Au;-41 :uo 2.9S Aui;:-46 3.02 2.il Aui;:-51 3.4:l 3.19 Scp-21 8.30 732 Sep-26 :5.62 5.17 Sep-31 7.04 5.05 Sep-36 4.54 4.05 Sep-41 3.30 3.00 Sep-46 3.06 2.75 Sep-51 3.4-! 3.14 Oet-21 8.40 7.04 Oct*:!6 5.61 5.IS Oct-31 8.01 5.54 Oc:t-36 4.53 4.04 Oct-41 3.82 3.00 Oct-46 3.06 2.76 Oet-51 3.49 3.17 Xov-21 7.92 6.55 :,.l'ov-26 5.SS S.IS Nov-31 7.SO 5.51 Nov-36 4.5] 3.95 Nov-41 3.S2 2.9S Nov-46 3:.07 2.76 Ncw-51 3.49 3.24 Dec-21 7.68 6.:32 Dee-26 S.54 5.12 Dcc-31 S.S! G.24 Dee-36 4.53 3.S3 De,:-41 3.35 3.06 Dcc-46 3.07 2..76 Dec-51 3.53 3.29 J:tn-22 7.'3 6.41 Jan-27 5.51 5.10 Jzn..32 8.18 6.17 J.:n-37 4.50 3.S2 hn-42 3.S3 3.09 fan-47 3.05 2.72 J:n-52 3.57 3.29 Feb-22 7.74 6.32 Feb-27 5.54 5.13 Feb-32 S.33 6.41 Feb-37 4.55 3.S9 Feb-42 3.Sl 3,09 Feb-47 3.03 2:n Feb-52 3.55 3.23
}.far-22 1.55 6.22 MM-27 5.54 5.13 M:ir-32 S.31 6.06 }.-fur-37 4.76 4.00 :),far-42 3.S4 3.12 MM-47 3.04 2.72 ).-fa.r-52 3.55 3.25
~-22
"'>'22 7.29 6.86 6.06 5.93 Apr-27 M2y-27 Jun-27 5.49 5.50 '*"'
Apr-32 1Uy-32 9.56 10.21 6.SJ 7.36 Apr-37
}.{ay-37 4.98 5.02 4.07 4.00 Apr-42
~Uy-42 3.79 3.76 3.09 3.10 Apr-47 M>)'-47 3.IJ.I 3.03 2.70 2.70 Apr-52 l\fay-52 3.54 3.54 3.23 3.22 Jun-22 6.92 5.91 5.51 5.05 Jun-32 10.70 7.57 fan.Ji 5.17 3.99 Joo-42 3.73 3.12 fon-47 3.04 2.71 Jun-52 3.55 3.22 Jul-22 6.83 5.&9 Jul-27 5.48 s.os Jul-32 10.11 7.28 Jul-37 :5.0S 3.94 Jul-42 3.68 3.10 Jul-47 3.03 273 Jul-52 3.53 3.22 Aus:-22 6.SS S.S6 Auc-27 5.43 5.02 Aug.-32 7.92 G.35 Aus-37 S.04 H9 Au.;-42 3.67 3.10 Aug-47 3.02 2.73 Aus-S2 3.50 3.24 Sep-22 6.77 5.69 Sep-27 5.41 4.9S Sep-,32 7.4S 5.91 Sep-37 5.25 3.96 Sep-42 3.66 3.08 Sep-47 3.06 2.SO Sep-52 3.50 3.24 Oet-22 6.51 5.S3 Oct-27 5.39 4.95 Oet-32 i.Si 5.SJ Oct-37 5.53 4.09 Oc:t-42 3.6:S 3.08 Oct-47 3.13 2.SS Oct-52 3.50 3.26 Xov-22 656 5.S7 Nov-27 5JS 4.92 Nov-32 S.32 5.SS );ov-37 5.59 4.08 1':ov-42 3.67 3.07 Nov-4i 3.IS 2.93 Nov--52 3.4i 3.24 De:-22 6.56 S.9S Dec:*27 S.32 4.SS Dec-31 S.41 5.SS ~-37 S.60 4.03 Dec-12 3.6S 3.06 Dec-47 3.25 3.05 Dec-S2 3.50 3.22 Jun-23 6.59 5.&5 J:m-2S S.24 4.S5 J:in-33 S.S6 5.39 Jm-38 5.59 4.01 J:m-13 3.65 J.OS Jan-48 3.30 3.05 fan-53 3.51 3.25 Feb-23 6.6-0 5.33 Feb-2S 5.20 4.85 Feb-33 7.58 5.11 Feb-3S 5.79 4.03 Feb-4-3 3.61 3.02 Fcb-48 3.3i 3.05 Feb-53 3.53 3.30 r-.far-23 6.73 6.06 M:u'*2S 5.JS 4.82 ?i.far-33 7.SS 6.34 ).hr-JS 5.80 3.99 Ma:r-43 3.5S 3.01 ).llt-4S 3.29 3.02 Mu-53 3.56 3.36 Apr-23 6.7S 6.04 Apr-2S :5.lS 4.S2 Ap:-33 7.1S 6.S9 Apr-JS 5.S2 4.0S Apr-43 l.60 3.00 Apr-4S 3.28 2.97 Apr-53 3.62 3.47 May-23 Jun-23 Jul-23 6.78 6.80 6.79 6.00 6.06 6.02 Jun-28 Jul-28 5.23 5.38 5.38 4.$7 4.99 S.04 May-33 Jun-33 Jul-33 7.17 7.20 i.36 6.$0 6.11 5.91
?..fay-3S Jun-JS Ju!-3S 5.32 5.33 5.01 3.95 3.95 3.S6 1fay-43 Jun-n Jul-43 3.60 3.60 3.55 3.00 2.98 2.96 M.ay-4S fon-4S fol-48 3.27 3.29 3.34 2.94 2.94 2.99
- -.tay-53 Jun-53 Ju!-53 3.76 3.SO 3.83 3.63 3.71 3.66 Aug-23 6.71 S.77 Au;;-2S 5.43 5.0S Aug:-33 7.6& 5.9S Aug-JS 4.93 3.S4 Aug-43 3.55 2.96 Aug-48 3.40 3.03 Aug-53 3.SS 3.61 Scp-23 6.Sl S.95 Sep-2S SAS 5.05 Sep-33 7.62 6.36 Sep-38 5.05 3.88 Sep-43 3.55 :.96 S,p--48 3.42 3.05 Sep-53 3.93 3.62 Oct-23 6.19 5.9S Oct-ZS 5.43 4.99 Oct-33 7.3S 6.36 Oct-JS 4.90 3.79 Oc:t-43 3.53 2.97 Oa-4S 3.44 3.03 Oct-53 3.S6 3.49 Nov-23 6.78 6.00 :-:ov-2S 5.3S 4.9S Nov-33 7.21 7.06 ~ov-38 4.71 3.73 Nov-43 3.55 2.9S Nov-4S 3.4S 3.07 Nov-53 3.7S 3.40 Dec-23 6.SO 6.05 Dce-2S 5.32 5.05 Dec-33 7.03 7.22 Dec-38 4.77 3.74 Dee-43 3.55 2.99 Doc-4S 3.47 3.06 Dei:-53 3.72 3.3S
Schedule AHG-1 15-WSEE-115-RTS
)..foody's Public Uiiity BoodD:ita )..foedy's Public Crility J3.ornl Dab 1foody's P..>blic Utility Bond Dm Moody's Public Utility Bond D:tt:'! Moody's. Public 'wtility Bond Dm Moody's Public 'Utility Bond Dau Mcod}'s Public Uo1ity Bend D:it:i B~ A B~ A B,u A Bu A Bu A B:u A B,u A J:m-54 3,72 3.32 J:m-59 4.71 4.52 fao-64 4.74 4,49 Jan-69 7.42 7.04 Jan-74 8.58 S.36 fa,-i-i9 10.29 9.90 fan-S4 14.05 13.39 FC0-54 3.69 3.13 Feb-59 4.77 4.50 F,b-6-1 4,74 4.50 Fob-69 7.39 7.13 Feb-74 S.6S S.4'2 Feb-79 10.27 9.S4 Feb-S4 14.05 13.41 Mar-54 3.58 3.16 M~-59 4.59 4.47 r-W-64 4.73 4.51 tfar..69 7.61 7.'27 1iar-74 S.Sl S.46 r,1:i.r.79 10.53 10.04 Mar-S4 14.56 13.87 Apr-S4 3.53 3.16 ,4..pr-59 4.6S 4.56 Apr-64 4.75 4.52 Apr-69 7.6S 7.30 Apr-74 9.04 ,.11 Apr-i9 10.56 IO.IO Apr*S4 14.82 14.16 11.ty-54 3.51 3.14 i'>fay-59 4.S7 4.77 Mzy-64 4.73 4.53 M'ay-69 7.56 7.16 M:i.y-74 9.23 9.00 )..fay-79 10.70 !0.30 ~b.y-S4 15..2S 14.90 Jun-54 3.50 3.16 Jun-59 4.97 4.66 Juo-64 4.74 4.55 Jun-69 7.77 7.41 Jun-74 9.48 9.32 Jun-79 10. .56 10.14 l~-S4 JS.SO 15.09 Jul-54 3.48 3.14 Jul-59 5.03 4.SS Jul-64 4.75 4.54 Jul-69 7.92 7.52 Jul-74 9.72 9.66 Jul-79 10.4S 9.9S Jul-S4 15.50 14.S2 Aug-54 3.47 3.13 Aug-59 5.04 4.89 Allg.M *US 4.54 Aus-69 7.S2 7.,14 Au:;_-74 10.14 10.03 Aus-79 10. .50 10.14 Aug-S4 \4.79 14.43 Sep-54 3.44 3.12 Sep-59 S.!7 5.03 Sep-54 4.T.i 4.53 S<p-69 S.11 7.63 Sep-74 10.59 10.45 Sep-79 10.7S 10.36 Sep-S4 14.51 14.17 Oct-54 3.41 3.12 Oa-59 5,29 4.96 0\."t-64 4.72 4.51 Oct-69 S.47 S.02 Oct-74 11.03 I0.7S Oct-79 !I.S9 11.40 Oct*S4 14,17 13.SO
- ,..'ov-54 3.39 :u1 ~ov-59 5.20 4.90 Nov-64 4.72 4.53 Xov-69 S.53 8.00 N'ov-74 Jl.38 I0.46 Nov-79 l2.4S ll.S9 Nov-84 13.72 13.23 Dec-54 3.38 3.!I Dec-59 5.13 4.96 Doo-64 4.i2 4.54 Dee-69 S.S9 S.59 Dec-74 11.40 10.27 D.x-79 12,51 11.79 Doo-S4 13.46 13.11 J::o-55 3.37 3.13 Jan-60 5.20 5.02 Jan-65 4.71 453 Jan-70 9.00 8.69 J:i.n-75 Jl.57 10.37 J:ui-SO 12.92 12.27 hn-SS 13.36 12.99
,.co Fcb-55 M'.u-55 3.3S 3.3S 3.14 3.15 Feb-60
?.hr--60 5.13 5.11 4.91 Feb-65 r...ra.-os 4.69 4.6S 4.51 4.50 Feb-70 M:u-70 '*"
S.Sl S.Sl S..31 Feb-75
~far-75
!l.32 10.94 9,99 9.i:!
Feb-SO
)l.iaf.SO 14.42 1.5.26 13.55 14.65 Feb-as Mar-SS 13.44 14.19 13.0S 13.87 Apr-55 3.40 3.I5 Apr-60 4.96 4.79 Apr-65 4.69 4.49 Apr-70 S.94 8.31 Apr-75 10.S6 10.06 Apr-SO 14.35 l3.S7 Apr SS 0 14.11 13.61 M:iy-55 3.40 3.!9 May-60 5.08 4.86 t.fay-65 4.71 4.50 May-70 9.10 S.67 :\by-75 !0.95 10.23 May--30 !2.93 i2.53 :\Uy-SS 13.62 13.12 Jun-55 3.41 3.21 Jun-60 5.05 4.84 Jun-65 4.77 4.52 Jun-70 9.52 9.04 Jun-75 JO.S5 JO.IO Jun-SO 12.63 12.21 Jun*SS 12,66 l2..l3 Jul-55 3.43 3.21 Jul-60 S.03 4.79 Ju!-65 4.7S 4.54 Jul-70 9.4S 9.06 Jul-75 JO.SO JO.OJ Ju1-S0 12.75 11.26 Ju!-SS 12.70 12.07 Aug-55 3.46 3.24 Aui;-60 4.81 4.64 Aug-65 4.79 4.5S Aus-iO 934 s.ss Aug-75 J0.S7 10.12 Aug-SO 13.50 1'2.96 Aug-SS 12.73 12.13 Sep-55 3.48 3.27 Sq,-60 4.71 4.57 S<p-65 4.82 4.63 Scp-70 932 S.S2 Sep-75 !O.S9 10.19 Sop-SO 14.07 13.43 Sep-S5 12.il 12.13 Oct-55 3.47 3.30 Oct-60 4.S2 4.61 Oct-65 4.SS 4,66 Oct-70 9.27 8.76 Ckt-75 10.S9 10.16 Oct-SO 14.43 13.SS Oct-SS !2.52 J:tO!
~ov-55 3.48 3.32 ~ov,..60 4.30 4.61 Nov-65 4.S9 4.71 :Sov-70 9.29 S.79 Nov-75 10.n 10.04 Noy-SO 14.79 14.12 NOY--&5 12.04 11.49 De,-,S 3.50 3.35 Doo-60 4.iS 4.65 D<<-65 4,97 4.S3 Dec-70 9.04 S.48 Dec-75 10.79 JO.I! D.x-SO 15.19 14.63 Dte-85 ll.4S 10.97 Jm-56 3.50 3.31 fan"6I 4.79 4.64 Jon-66 4.99 4.86 Jan-71 S.76 8.15 Jan-76 10.55 9.90 fa.,_S.I 15.30 14.26 J:m-S6 11.24 10.79 Feb.56 3.50 3.29 Feb-61 4.76 4 . .59
- Feb-66 5.02 4.9:? Fcb-71 S.SS 7.89 Feb-76 J0.31 9.71 Feb-SI IS.S6 14.91 Feb-S6 10.74 10.26 Mu-56 3.51 3.29 :-.W-61 4.72 4.4S M;u-66 5.19 5.14 Mlr*7l S.63 8.05 }.far-71.i 10.17 9.67 Mar-SI IS.SJ 15.!4 Mu-S6 9.91 9.48 Apr-56 3.59 3.40 Apr-6! 4.74 4.4S Apr-66 5.39 5.25 Apr-71 S.5S S.07 Apr-76 9.95 9.53 Apr-SI 16.14 15.4S Apr-S6 9.63 9.14 i'>fay-56 3.62 3.4S 1hy-6l 4.77 4.52 :\Uy-66 5.44 5.1S :\-fo.y-71 S.6S SJ4 May-76 9.9! 9.55 ).by-SJ 16.66 16.25 :-.&y-S6 10.02 9.59 Jun-56 3.65 3.49 J<m-<il 4.7S 4.S7 Jun-66 5.52 5.40 Jun-71 8.79 S.45 Jun-76 10.01 9.54 Jun-81 16.30 15.74 Jun-S6 10.03 9.62 Jul-56 3.70 3.55 Ju!-61 4.S4 4.65 Jul-66 5.61 5.45 Jul-71 8.78 8.45 Ju!-76 9.SS 9.37 Jul-SI 16.98 16..21 JuJ.g6 9.69 9.37 Aus-56 3.S4 3.63 Au:;-61 4.90 4.73 Aus-66 5.79 5.SS. Aui;-il a.ao 8.40 Aus;-76 9.67 9,13 Aus-SI 17.19 16.5S Aug-S6 9.70 9.29 Sep-56 Oc:-56 4.02 4.15 3.72 3.79 S<p-61 Oct-61 4.91 4.92 4.73 4.71 S<p-66 Oct-66 6.06 6.07
.5.Sl 5.74 Sep-7!
Oct-71 S.59 8.43 8.18 S.10 Sep-76 Oct-76 9.47 9.41 '*'° 8.79 Sc;>-St Oct-SI 17.76 17.71 17.16 17.21 Scp-S6 Oct-S6 9.96 9.52 9.52 9.52 Nov-56 4.15 3.S2 Nov,.61 4.S9 4.6S Nov-66 6.06 5.63 Nov-71 S.47 7.96 Kov-76 9,34 S.76 Nov-SI 16.49 16.20 Nov-S6 9.69 9.28 Dec-56 4.IS 3.91 Dec-61 4.SS 4.65 Dee-66 6.09 5.67 Dcc-71 8.44 7.90 De.::-76 9.21 S.62 Dec-Sl 17.02 16.29 D~-S6 9.49 9.12 fan-57 4.26 3.96 Jan-62 4.86 4.65 fan-67 5.S3 l.46 Ja.....72 S.37 7.79 Jan-77 9.17 S.61 Jan-S2 17.SJ 16.83 Jan-S7 9.2i S.95 Fc:>-57 4.26 4.05 Fcb-62 4.86 4.66 Feb-67 5.63 5.28 Feb-72 S.32 7.73 Feb-77 9.19 S.65 Fcb--&2 17.33 16.S4 Fd>-S.7 9.24 9.00
)..iu-57 4.25 4.05 Milr-62 4.85 4.64 M:u-67 5.69 5.44 )..{:ir.72 8.26 7.77 :\fu-77 9.20 S.70 Mz-82 Ii.16 16.50 Mar-Si 9.19 S.93 Apr-57 4.14 4.01 Apr-62 4.SI 4.59 Apr-67 5.74 5.42 Aj<-72 S.30 7.S2 Apr-77 9.17 S.71 Apr-S2 17.00 16.31 ,\pr-S7 9.85 9.3S 1Uy-57 4.28 4.01 :-.Uy-62 4.74 4.51 :\fa.y-67 5.93 5.66 !.ily-71 8.30 7.S4 }.-by-77 9.13 5.7: May-S2 !6.6S 16.04 M;ty-S7 10.40 9.91 Jun-57 4.33 4.09 Jun-62 4.6& 4.4S Jun-67 6.14 l.S4 Jun-72 8.31 7.77 Jun-77 9.02 S.5S Jun-32 17.21 16.42 Jun-S7 10.46 10.02 Jul-57 4.41 4.20 Jul-62 4.6S 4.50 Ju!-67 6.23 5.94 Ju!-72 8.36 7.82 Jul-77 S.97 S.SI Jul-S2 17-09 16.42 Jul-S7 10.62 IO.IS Aug-Si 4.19 4.37 Aug-62 4.72 4.53 Aug-67 6.29 5.96 Aug-72 8.22 7.64 Au:;-77 S.91 S.49 Aug-82 16.37 15.83 Au:;-S7 10.90 10.45 Sep-Si 4.66 4.55 Scp-62 4.74 4.51 S<p-67 6.32 6.05 S.,,-72 8.01 7.61 Sq,-77 s.ss S.46 Se;,-82 15,58 15.40 Sep-S7 11.58 ll.22 Oct-57 4.73 4.61 Oct-62 4.71 4.49 Oct-67 6.42 6.IS Oct-7.? 7.94 7.66 Oct-77 9.01 S.61 Oct-S2 15.10 14.79 Oct-S7 ll.29 J0.75 Nov-57 4.S2 4.62 ~ov-62 4.65 4.45 Nov-67 6.63 6.4& Nov-72 7.86 7.60 Nov-77 9.05 S.64 Xov-32 14.Sl 14.46 N'ov-87 ll.1S lo.61 Dec-Si 4.Sl 4.36 Dee-62 4.66 4.44 Dee-67 6.9I 6.67 Dec-72 7.7S 7.4S Dec-77 9.0S S.64 Det:-S2 14.69 14.43 Dec-S7 11.09 1054 131'1-Si 4,65 J:n-6S S.92 l4.S6 fan-SS JO.SO Feb-58 MU-SS 4.60 4.23 4.15 3.93 3.%
4.13 Jan-63 Fd>-63 Mu-63 4.65 4.66 4.39 4.37 4.37 Fcb-6&
)..fat-6S 6.76 6.6S 6.75 6.37 6.41 J:m-73 Fro-73 Mar-73 7.77 7.SS 7.95 7.52 7.62 7.66 fan-78 Fcb-78 M::--7S 9.27 9.29 9.37 S.97 8.9S Jan-SJ Feb-SJ
~fat-S3 14.61 14.33 14.24 14.26 13.94 Feb-SS Mar-SS 10.23 10.43 9.96 9.70 9.$4 Apr-58 4.15 3.95 Apr-63 4.67 4.37 Apr-68 6.94 6.SS A;ir-73 7.% 7.63 Apr-7S 9.54 9.09 Apr-SJ 14.07 13.61 Apr-SS 11.0S 10.40
~*-58 4.23 -tot May-63 4.67 4.37 May-6S 6.99 6.62 :\1ay-73 7.91 7,63 .1,.13y-7S 9.70 9.2'2 h-tay-SJ 14.05 13.SO May-SS U.2S 10.72 Jir.-SS 4.20 3.99 Ju.n-63 4.67 4.37 Jun-6S 7.01 6.62 Jun*73 7.94 7.71 Jun-7S 9.7S 9.40 Jun-83 14.16 13.64 Jun-SS 11.00 10.53 Jul-SS 4.19 4.04 Jul-63 4.67 4.39 Jul-68 6.9:? 6.53 Ju!-73 8.10 7.S2 Jul-7S 9.73 9.5[ Jul-S3 14.01 13.58 Ju1-SS 11.22 10.75 Aus;-5S 4.44 4.29 Al.lg-63 4.66 4.3S Au;-6S 9.72 6.27 Aus-73 S.47 8.04 Aus-73 9.53 9.32 Au:;-83 14.21 13.57 Aug-SS 11.39 l0.S9 Sep-5S 4.69 4.55 S<p-63 4,69 4.40 Sep-6S 6.67 6.27 Scp-73 8.61 3.04 Sep-7S 9.47 9.28 Sep--83 14.10 13.42 Sep..SS !0.92 10.41 Oct-SS 4.74 4.56 Oct-63 J..66 4.41 Oct-6S 6.74 6.40 Oct-73 S.44 8.02 Oct-ii 9.69 9.46 Oct-83 13.9.5 13.25 Oct-SS JO.JI 10.0!
- -:ov-ss Nov-Sl!.
Dec-5S 4.67 4.65 4.47 4.49 Nov-63 Dee-63 4.6S 4.73 4,42 4.46 Nov-6S Dee-6S 7.01 7.23 6.59 6.S7 Nov-73 Dec-73 S.44 8.51 8.15 S.24 Nov-78 Dcc-7S '*"
to.OS 9.6S 9.70
!',"OY-83 De.::-S3 14.12 14.23 l3.3S 13.52 Dcc-SS 10.35 10.*14 9.90 10.06
Schedule AHG-1 15-WSEE-115-RTS Moody's Public Utility Bend D~ Moody's Public Utility Bond Ir..t1 Moody's Public Utility Bond Da!3. M:oodys M!ic Utility Sood Dau Moody's Public: Utility Bond D:.t:i Mood)ls Pub!ic U':ility Bond Dat:l.
Ba:?. A Bu A Bu A Bn A BM A Bu A j:iziA!.9 JO.JS JO.OS Ja.'l-94 7.66 733 J:m.-99 7.30 6.97 fan.04 6.47 6.16 J:m-09 7.90 6.39 fan-14 5.09 4.63 Feb-89 IOJS IO.Oi F~b-94 7.76 7.47 Feb-99 7Al 7.09 Fcb-04 6.23 6.1$ Feb-09 7.74 6.30 Fcl>-14 5.01 4.53
).{u-S9 JO.SO !0.23 '.\br-94 !Ul 7.SS M.,,-99 7.55 7.26 Y..iT-04 6. ~3 5.97 Mar-09 S.00 6.42 M.u-14 ,.oo 4.51 Apr..S9 10.49 tO.IS Apr-94 S.47 8.12 Apr-99 7.51 7.22 Apr-04 6.46 6.3S Apr-09 8.03 6.4S Apr-14 4.SS 4.41
'.\fay-S9 10.29 9.99 May-94 8.61 S.33 Mav-99 7.74 7.47 M,y-04 6.75 6.62 :-.tay-09 7.76 6.49 M:1y*14 4.69 4.26 Jun-&9 9.80 9.64 Jun-94 8.64 8.31 J~-99 MJ 7.74 Ju.n-04 6.34 6.46 Jun-09 7.30 6.19 Jun-14 4.73 4.29 Jul*S9 9.64 9.50 Jul-94 8.80 S.47 Jul-99 7.97 7.71 fol.Q4 6.67 6.27 Jul-09 6.$7 5.97 Jul-14 4£6 4.23 Aus;-S9 9.64 9.52 Au;;-94 S.74 S.41 Auz:-99 S.16 7.91 Aui;-04 GAS 6.14 Aug-09 6.35 S.7l AUg*l4 4.6$ 4.13 Sep-S9 9.70 9.SS Stp-94 S.9S S.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 9.SJ. S.06 Oct-89
- -,'ov-S9 9.64 9.64 9.51 Oct-94
~ov-94 9.::4 9.3$
S.S6 S.9S Ck<*99 Nov-99 S.32 s.?2 7.94 Oa-04 Nov-04 6.:7 6.16 5.94 5.96 Oct-09 Nov-09 6.22 6.16 ,....
5.64 Oa-14
- -l'ov-t4 4.67 4.75 4.06 4.09 Oec-S9 9.60 9.44 Dec-94 9.16 S.76 De{:*99 S.2S S.14 Dei.:-04 6.!0 5.92 D<c-09 6.27 5.8.3 0>!{:*14 4.70 3.95 J:m-90 9.74 9.56 Jan-95 9.15 S.73 Jm-00 S.40 S.35 Jan-OS 5.95 5.7& J::n*lO 6.13 5:n J:m-15 4.39 3.58 Feb-90 9.% 9.76 Feb-95 8.93 S.S2 Fcb-0-0 S.33 S..2S Feb-05 5.76 5.61 Feb-IO 6.27 5.8S Feb-IS 4.44 3.67 10.06 s..zs Mar-90 Apr-90 10.13 9.8S 9.92 M3r-95 Apr-95 S.7S S.67 S.37 8.27
~hr-00 Apr-00 S.40 8.40 S.29
'.\far-05 Apr-05 6.00 5.95 5.33 5.64
- .\far*IO Apr-IO 6.24 6.06 '*"
5.66 M:ir-15 Apr*lS 4,51 4.51 3.74 3.75 M:.y-90 10.16 10.00 M,y-95 a.JO 7.91 M:iy-00 8.86 S.iO !\hy-05 s.ss 5.53 ?,fay-IO 5.97 5.44 ~fay*U 4.91 4.17 Jun*90 9.96 9.SO Jun-95 S.01 7.60 Jw,.00 8.47 3.36 Jun-05 5.70 s..:o Jcn-10 6.18 5.46 Jul-90 9.92 9,75 Jul-95 S.l! 7.iO Jul-00 S.33 8.25 Jul-OS 5.SO 5.51 Jul-10 5.98 5.:6 Au;;-90 10.12 9.92 Aui;-95 S.24 7.83 Aug:-0-0 S.25 S.13 Aug-05 5.80 5.50 Aug-JO 5.55 5.01 S,:p-90 !0.32 10.12 Sep-95 7.98 7.62 Sop-00 S.32 g_23 Sep-05 5.83 5.52 Sep-IO 5.53 5.01 Oct-90 I0..2S 10.05 Oc!-95 7.32 7.46 Oct.CO S.29 S.14 Oa-05 6.08 5.79 O::t-10 5.62 5.10
~ov-90 10.12 9.90 Nov-95 7.81 7.-13 :Sov-00 8.25 S.11 Nov-05 6.19 5.SS ~ov-.10 5.85 5.37 Dec-90 9.9S 9.73 De.:-95 7.63 7.23 Dec-00 S.01 7."4 Dee-05 6.14 5.i9 Dee-10 6.04 5.56 J:.n-91 9.96 9.71 Jan-96 7.64 7.21 fan-01 7.99 7.SO Jan-06 6.06 5.74 Jtn*ll 6.06 5.57 Feb-91 9.6S 9.47 Feb-96 7.7S 7.37 Feb.(11 7.94 7.74 Fi:b-06 6.11 5.S2 Feb-II 6.10 5.68 Mar-91 9.74 9.55 !\tar-96 8.15 7.73 MM-01 7.SS 7.6S '.\ur-06 6.26 S.98 Mar-II S.91 5.56 Apr-91 9.64 9.46 Apt-96 S.32 7.S9 Apr-01 S.06 7.93 Apr-06 6.54 6.29 Apr*ll 5.9S 5.55
'.\fay-91 9.64 9.44 ~:ty-96 S.45 7.98 May-OJ S.11 7.99 Ma:y-06 6,59 6.4! Mzy-ll 5.74 5.32 Jt:n-91 9.79 9.59 Juo-96 S.5I S.06 Jtm-01 S.02 7.85 Jun.-06 6.61 6.40 Jun-11 5.67 S.26 Jul-91 9.69 9.55 Ju'.-96 S.44 3.02 Jul-DI 8.05 7.78 Jul-06 6.61 6.37 Jul-!! 5.70 5.27 Aug.-91 9.47 9.29 Aug-96 S.2S 7.84 Aug-01 7.95 7.59 Aui;-06 6.43 6.20 Aug-11 5.22 4.69 Sep-91 9.35 9.15 S,p-96 S.41 8.01 S,p-01 S.12. 7.75 S,p-06 6.26 6.00 Scp.ll 5.11 4.4&
Oct-91 9.32 9.12 Oct-96 S.15 7.77 Oct--01 3.02 7.63 Oa-06 6.24 5.98 Oct-11 S.14 4.52 Nov-91 9.2S 9.05 ~ov-96 7.87 7.49 Xov--01 7.96 7.57 Xov-C6 6.04 5.S.O Xov-1! 4.93 4.25 Dec-91 9.07 8.SS Dec-96 7.9S 7.59 Dec-01 8.27 7.S3 D<<-06 6.05 5.:U Dcc*ll 5.Q7 4.33 J:n-9:!
Feb-92 S.9S 9.09 '*"
S.93 J:m-97 Feb-97 S.18 8.02 7.77 7.64 Jm-02 Fcl>-02 3.13 8.13 7.66 7.54 Jan-07 Feb-07 6.16 6.10 5.96 5.90 J:n-12 Feb-12 5.06 5.02 4.34 4.36 Mz-92 9.16 3.97 ).Uf-97 8.26 7.87 Mar-02 S.31 7.76 :-.ar--01 6.10 5.85 ?'-.br-12 5.13 4.4S Apr*92 9.l! S.93 Apr-97 S.42 8.03 Apr-02 S..25 7.57 Apr--07 6.24 5.97 Apr-12 5.11 4.-10 May-92 9.0! S.S7 M:t)*-97 S.2S 7.S9 M:i.y-0:!. 8.33 7,52 t'.by-07 6.23 5.99 }.U)'-12 4.97 4.20 Jun-92 S.99 S.7S Jun-97 8.12 7.72 fon-02 S.25 7.41 Jun-07 6.54 6.30 Jun-12 4.91 4.0<
Jul-92 S.69 8.57 Ju!-97 7.S7 7.48 Jul-02 8.0S 7.31 Jul-07 6.49 6.25 Jul-12 .us 3.93 Aug-92 s.ss S.4J. Aug-97 7.93 7.Sl Aug-02 7.74 7.17 Aus-01 6.Sl 6.24 Aug-12 4.8S 4.00 Sep-92 S.54 S.40 S,p-97 7.S4 7.58 Scp-02 7.6.2 7.03 Sep-07 6.45 6.1S Scp-12 4.Sl 4.02 Oa-9.2 S,76 S.54 Oct-97 7.67 i.35 Oct-02 7.99 7.23 Oct-07 6.36 6.11 Oct-12 4.54 3.91 Nov-92 8.86 3.63 :Sov-97 7.49 7.25 Nov-02 7.75 7.14 Xov-07 6.27 5.97 }.av-12 4.42 3.S4 Dee-92 S.69 8.43 Dee-97 7.41 7.16 Dcc-02 7.60 7.06 O!c-07 6.51 6.16 Dce-12 4.55 4.00 fan-93 '57 S.27 far.-9S 7.28 7.04 hn*03 7.47 7.06 Jan.CS 6J5 6.02 J:n-13 4.66 4.15 Feb-93 S.31 8.04 Feb-9S 7.36 7.12 Feb-03 7.17 6.93 Feb-CS 6.60 6.21 Feb-13 .!.74 4.lS Mar-93 S.10 7.99 Z..fur-9S 7.37 7.16 M:u-03 7.0S 6.79 l>far-OS 6.63 6.21 ),far*n 4.72 4.20 Apr-93 S.11 7.Sl Apr-98 7.37 7.16 Apr-03 6.93 6.64 Apr-OS 6.Sl 6.29 Apr-13 4A9 4.00 M:ly-93 s.a 7.86 ~fay-9S 7.34 7.16 '.\b.y-03 6.47 6.36 :.fay-OS 6.79 6.23 ~1'.:t)... 13 4.6S 4.17 Jun-93 S.05 7.75 Jun-98 7.21 7.03 Jun-03 6.29 6.21 Jun-OS 6.93 6.3S Jun-13 5.08 4.$3 Jul-93 7.93 7.54 Jul-98 7.24 7.03 Jul-03 6.65 6.56 Jul-OS 6.97 6.40 Jul-I3 5.21 4.6S Aus-93 7.59 7.25 Aug-9S 7.20 7.00 Aug-03 7.09 S.79 Aug-CS 6,98 6.37 Aur;-13 5.2S .1.73 Sep-93 7.35 7.04 Sep-9S 7.13 6.93 Sep-03 6.S7 6.56 Sep-OS 7.15 6.49 Sep-13 5.31 4.SO Oct-93 7.27 7.03 Oct-98 7.13 6.96 Oct-03 6.7S 6.42 Oct-CS 8.58 7.56 Oct-13 5.17 4.70 Xov-93 7.69 7.30 Nov-98 7.31 7.03 No\*-03 6.69 6.37 Nov-CS S.98 7.60 ~ov-13 5.24 4.77 Dec-93 7.7J 7.34 Dec-98 7.24 6.91 DC{:-03 6.61 6.27 Dec-CS S.!! 6.52 Dec*l3 5,25 4.Sl
Schedule AHG-10 15-WSEE-115-RTS WOLF CREEK DECOMMISSIONING COSTS EXTERNAL TRUST FUND Review of2014 Cost Estimate
"**ADJUSTED TO REFLECT KCC STAFF INPUTS***
in2014 S 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 CURRENT VALUE OF TRUST (12/31/14) s [80,829,742 Adjusted to Reflect Taxes on Unrealiz EQUIVALENT BEFORE TAX RETURN: THE EXPECTED INVESTMENT RETURNS ARE SHOWN ON PAGE 2 OF 2 PAYMENT GROWTH AlvlOUNT $0 GROWTH RATE FOR COSTS (INFLATION) 3.15%
- OF PERJODS FOR ANALYSlS 30
- OF PERJODS - l 29 PERIOD OF PAYMENTS MIDYEAR DECOM!v!ISSIONING PERIOD IN YEARS 9 FUND MANAGER FEES 0.576%
BEGIN YR. DECOM ANNUAL EARNINGS END YR.
LINE YEAR BALANCE EXPENSE CONTRIB. AFTER FEES BALANCE AND TAXES 2012 2013 2014 2015 $180,829,742 $2,762,483 $9,161,452 $192,753,677 2 2016 192,753,677 5,772,700 9,844,745 $208,371,122 3 2017 208,371,122 5,772,700 10,629,297 $224,773,119 4 2018 224,773,l 19 5,772,700 11,453,263 $241,999,082 5 2019 241,999,082 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 299,045,187 5,772,700 15,184,369 $320,002,257 9 2023 320,002,257 5,772,700 16,237,162 $342,012,118 10 2024 342,012,118 5,772,700 17,342,842 $365,127,660 11 2025 365,127,660 5,772,700 18,504,066 $389,404,427 12 2026 389,404,427 5,772,700 16,702,987 $411,880,114 13 2027 411,880,114 5,772,700 17,659,005 $435,311,819 14 2028 435,311,819 5,772,700 18,655,688 $459,740,207 15 2029 459,740,207 5,772,700 19,694,766 $485,207,673 16 2030 485,207,673 5,772,700 20,778,042 SSl l,758,415 17 2031 511,758,415 5,772,700 21,907,395 $539,438,510 18 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 21 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 ,7.07 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 76,742,107 1,443,175 15,496,371 $884,266,999 32 2046 884,266,999 170,390,309 13,361,348 $727,238,039 33 2047 727,238,039 209,293,207 10,189,818 $528,134,650 34 2048 528,134,650 156,404,173 7,349,097 $379,079,574 35 2049 379,079,574 127,253,390 5,101,820 $256,928,004 36 2050 256,928,004 114,089,268 3,136,287 $145,975,022 37 2051 145,975,022 58,558,037 1,854,229 $89,271,213 38 2052 89,271,213 54,764,209 915,049 $35,422,054 39 2053 35,422,054 35,623,101 202,618 SI,571
Schedule AHG-10 15-WSEE-115-RTS KCC Adjustments to Exucctcd Returns FEDERAL TAX RATE 20.00%
FOR THE YEARS 2012 THROUGH 2025 EXPECTED WEIGHTED AFTER INVESTlllENT MIX RETURNS RATIO RETURN TAX Large Cap 7.60% 30% 2.28% l.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% l.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% l.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%
JOO% 6.04% 4.83%
FOR THE YEARS 2036 THROUGH 2044 EXPECTED WEIGHTED AFTER INVESTl\IENT MIX RETURNS RATIO RETURN TAX Large Cap 7.60% [0% 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 DECOllH'IIISSIONING EXPECTED WEIGHTED AFTER INVESTl\lENT 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% 1.49% 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 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 CITY, MO 64108 jkylercohn@bkllawfirm.com Fax: 816-511-0822 andy.zellers@brightergy.com GLENDA CAFER, ATTORNEY TERRIPEMBERTON,ATTORNEY CAFER PEMBERTON LLC CAFER PEMBERTON LLC 3321 SW 6TH 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 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. sm ith@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 SW ARROWHEAD 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 SW ARROWHEAD 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 7400 W 110TH 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 STE 1900 2959 N ROCK RD STE 300 AUSTIN, TX 78701 WICHITA, KS 67226 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-RL/IP) 818 S KANSAS AVE 9275 GUNSTON RD STE 1300 PO BOX 889 FORT BELVOIR, VA 22060-5546 TOPEKA, KS 66601-0889 matthew.s.dunne.civ@mail.mil Fax: 785-575-8136 ca thy .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 BOX 889 PO BOX 889 TOPEKA, KS 66601-0889 TOPEKA, KS 66601-0889 cindy.s.wilson@westarenergy.com jeff. m arti n@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 VII to WM 19-0008 Order Approving Stipulation and Agreement (Docket No. 15-WSEE-115-RTS)
- (51 pages)
1 2015.09.24 10:47:44 K:m::--3=- CorPiJ r*a-tic,r, Commi:;sic,n 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, In~. 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. Introd1:1ction **************************************************************************************************~************************ 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. Standard of Review ...... _...................................................................................................... 25
- 1. .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 I 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
...)
1 Westar' s general rate case.
- 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 he~ring, amend settlement procedures, and divide the scheduled evidentiary hearing into two distinct phases. 2 1
A Petition Initiating Docket filed by Westar on September 15, 2014, gave rise to the present docket, Docket No.
15-WSEE-115-RTS.
2 See Order Modifying Procedural Schedule (Apr. 14, 2015); Order Modifying Procedural Schedule and Substituting Prehearing Officers (Jul. 14, 2015); Order On: Interventions, Petition For Leave To Issue Discovery, Motion To 2.
i*
I
- 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 Agree~ent (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 Partie~. 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 ld.
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&A]. 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. 66-10 la, 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 companies for the production, transmission, d~livery 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 Comrilission's* power, authority, and juri~diction, all incidental powers necessary to carry into 10 K.S.A.66-101; K.S.A. 66-lOla; K.S.A.66-104.
11 K.S.A. 66-lOla.
12 .
K.S.A. 66-l04(a).
13 K.S.A. 66- l Olb.
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.t!ie 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 O.ther 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 wit;nesses 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. 82-1-2.>.; I.
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
..,..,...,,,,=='"""""
,cl:~)~~y;;.'2t-, ____ *. ~..
_ 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
Kanas Industrial 1. I. Brian C.
Consumers Group 2. Andrews
- 3. 2. Michael P.
- 4. Gorman
- 1. Jeff Hoppe 1. Jeff Hoppe 1. JeffHoppe Federal Executive Agencies
- 1. Steve Chriss
- 14. In summation, by July 29, 2015, fifty-one witnesses from thirteen separafe 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 s*econd 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 maile!s 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 Consume~ Protection Division (PACP) caused to be filed in the record a report summarizing the public comments ,
received. 20 18 Order Modifying Procedural Schedule, 2 (Apr. 14, 2015).
20 Notice of Filing 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. 2-3
.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 I
I; . the July 21, 2015, Topeka public hearing, and forty-three comments during the July 23, 2015, j
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 appe~rance 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 of Appearance at Evidcntiary
-~~~f~-~
Amber Smith Michael Neele
~~*§.'
The Alliance for Solar Choice 1. Jacob Schlesinger
~~~ci~Jf'
{"~1'*1lhf<'!;
~t,7q~yi<>:.
Frontier El Dorado Refining, LLC 1. James Flaherty Wal-Mart Stores, Inc., Tyson Foods, Cargill, 1. David Woodsmall Inc.
Environmental Defense Fund 1. Robert Eye Kroger Co. 1.
Brightergy, LLC 1. Andrew Zellers 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- I 0.
26 Id. at JO.
27 Id. at I 0- I I.
28 Id at I l-12.
29 Id at 12-13.
30 Transcript ofEvid. Hearing at 47-55.
31 Id at 55-56.
32 Id at 56.
II
27: Staff called Justin T. Grady and Dr. Robert Glass to testify in support of the S&A33 and moved for admission into the record the prefiled testimony of Staffs remaining
- witnesses.34 . No party opposed the motion and the Commission admitted 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 testimqny. 38
- 29. All remaining parties who had previously filed direct, cross-answering, and rebuttal testimony in this proceeding, as described above, moved to have their respective witnesses' testimo~ies entered into the record. 39 No party objected to the admittance of the testimony into the record and the Commission admitted the same. 40 II. 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-J 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 Evid. Hearing at 66-68.
37 Id. at 68.
Js 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 c.ontained 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 Re:venue Requirement: The Joint Movants propose that Westar's net overall annual revenue increase should be set at $78,000,000.49 This revenue requiremeJ?.t does not include costs recoverable through Commission-approved riders. 50
- 34. Rebasing: The Joint Movants propose that Westar roU into base rates the existing balance in the Environmental Cost Recovery Rider (ECRR), including the amount updated in 41 SeeS&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 ,r 12.
so 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 oth~r 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 Staff's 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 reports that 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 Staff's 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 ,r 13.
52 Id. at,r 13.
53 Id. at ,r 13; S&A at Appendix A.
5
~ S&A at ,r 14.
55 Id.
56 Id. at ,r 15.
57 Id. at115.
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 Stafrs 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 61 established in Westar's next general rate case. No return on the regulatory asset will be
.allowed.62 The Joint Mo vants* agree that this particular ratemak.ing treatment should have no precedential value. 63
- 40. Discontinuance of Environmental Cost Recovery* Rider: The Joint Movant's 64 propos~ that Westar's ECRR should be discontinued. The Joint Movants agr~e that Westar would do a final update of environmental costs for 2015 that would have been recovered through 58 Id. at,r 16.
59 Direct Testimony of Adam Gatewood Direct on Beha1fofCommission Staff at 70 (Jul. 9, 2015); *s&A at ,r 17 .
60
. S&A at,r 18.
61 .
Id at ,r 18..
62 Id at,r 18.
63 Id. at ,r 18.
64 Id.atif19.
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 l, 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 cas!;! discussed below.
Westar will work with Staff to develop aprocess 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
!d at,r 19.
66 S&A at ,r 20; See Direct Testimony of Jeffrey W. Cummings on Behalf of Westar Energy, exhibit JC-!, as amended (Jun. IO, 2015).
67 S&A at ,r 20.
68 Id at ,r 21.
69 Direct Testimony of Chad Luce on Behalf of Westar Energy, 13 (Mar. 2, 2015).
70 S&A at ,r 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 !o 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 Testimo.ny 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) th~. 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 giyen 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.(RITODS): The Joint .Movants propose the Commission approve the changes in the Direct 71
/d at 122.
72
/d at,r23.
13 Id at 124.
74 Id. at ,I 25.
15 Direct Testimony of Mike Heim on Behalf of Westar Energy, 21 (Mar. 2, 2015) [hereinafter Heim Direct]; S&A at,r 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 1ncluded 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, "
S&A at ,r 27.
76 77 Heim Direct at 19-21. Note: Under Westar's current RITODS 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 ,r 28.
79 Id at ,r 28.
80 Id. atif29.
81 Id. at ,rJO.
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
.of return 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 resulti11:g 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 0f 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; i
- c. Regulatory asset associated with SCR Catalyst - fifty-four months; 82 at Id ,r 30.
83 Id. at ,r 30.
8-1 S&A anJ 31.
85 Id at ,r 3 I.
86 Id at ,r 32.
19
- d. Regulatory asset associated with Baghouse - six years;
- e. Regulatory liability associated with Stateline purchased power - three years;
- f.
- Pe~sion 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 EAS 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 Mova~ts 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 fil~ this abbreviated rate case*
87
. Id atif33.
88 Id at ,r 34.
89 Id at ,r 35.
90 S&A at ,r 35.
20
pursuant to K.A.R. 82-1-23l(b)(3). The cost of capital to be used for purposes of such proceeding is to be the overall rate of return 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 92 investments in grid resiliency projects discussed in paragraph 20 of the S&A, and the final roll-in of ECRR 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 I
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 ,r 35.
92 Id at ,r 36.
93 Id at ,r 36.
94 Id at ,r 37.
95 Id at ,r 38.
96 S&A at ,r 38.
97 Id at ,r 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 99 change could impact the economics of the customer's distributed generation.
- 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 100 distributed generation should be deferred to a generic docket. Westar and Staff .proposed working together to develop a procedural schedule for a generic docket in order to ensure timely 101 resolution of distributed generation issues to be addressed. The Joint Movants agree that they 102 will not oppose or seek to limit the participation of the Solar Parties in the generic proceeding. *
- 61. Residential Customer Charge: The Joint Movants propose that the monthly basic 103 service fee be $14.50 for all residential classes except for the Peak Management. The Joint 104 Movants proposed the monthly basic service fee for the Peak Management Rate be $16.50.
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. atif 38.
99 Id at ,r 38.
100 Unopposed Addendum, Addendum to Stipulation and Agreement.
IOI Id wz Id.
103 S&A at ,r 40.
104 Id. at ,r 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 L~rge 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 minimize 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 (TQC) 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 manufacture"r (LTM), interruptible service (IS) classes, or special contract customers. 111 Grid Resiliency Costs would be allocate~ to the remaining customer classes in the abbreviated rate case based on the same percentages reflected 105 Id. at ,r 41.
106 Id. at ,r 41.
107 Id. at ,r 41.
108 Transcript of Evid. Hearing at 50.
109 S&A at ,r 4 l(a).
110 Id. at ,r 42.
111 Id. at ,r 43.
23
in Appendix A of the S&A but adjusted proportionally to reflect the exclusion of the LGS, IL[>,
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. Continuing Discussions: The JointMovants 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. H 4
- 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 provid(ng efficient and sufficient 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 ,I 44.
114 Id. at,I 45.
115 S&A at ,I 46.
116 Id.
117 Id. at ~,I 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 public.11 9
- 71. The Kansas Supr~me Court ~andates the Com~ission 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 inter~sts 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 unr~asonably high as to b.e 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 Waterworks & Jmp.
- 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 £lee. 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 credii 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 opportuni!ies 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 depreciatiC?n allowance is to be earned." 130 These standards taken together stand for the general idea that the return provided to a 123 Order Approving Nonunanimous 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 for Electric Service, Docket No. 12-WSEE-112-RTS (Apr. I&, 2012) [hereinafter 12-112 Docket].
124 Bluefield Waterwprks & Imp. Co. v. Pub. Serv. Comm 'n ofW. Va., 262 U.S. 679,693 (1923) (emphasis added).
125 Fed Power Comm 'n v. Hope Natural Gas Co., 320 U.S. 591,603 (1944).
126 Bluefield Watenvorks, 262 U.S .. at 693.
127 12-112 Docket at 3.
128 Hope Natural Gas, 320 U.S. at 603.
129 Application at 10.
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 util_ity'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 Com.mission 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, Inc. v. Kansas City Power & light Co., 267 Kan. 760, 773 (1999).
132 Citizens' Viii. Ratepayer Bd. v. State Corp. Comm 'n ofState of Kansas, 28 Kan. App. 2d 313, 3 16 (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&Aintended 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 adde~dum.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-l-230a:
131 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.
142 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 po~ition regarding Westar's Application, 143 and when granted intervention, they were prohibited from participating 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 fili~g 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?*
I
- 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).
i.w Order Granting Limited Intervention at 2-3 (Aug. 11, 2015).
145 See K.A.R. 82- I -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.
8-1. 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 c
- 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 rebasing 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, retun;i _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 11-14 (Aug. 11, 2015) [hereinafter Greenwood S&A Testimony].
147 Id. at 11-12.
148 Id. at 12.
149 See id. at 12-14. .
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 ~&A represents a reasonable resolution of the
. . I 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 I
the zone of reasonableness. 155
- 85. Dr. Glass submitted testimony in support of the S&A. Spe~ifically, 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 Gener~!
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, Di:. 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 beh~lf of CURB, testified that the S&A is supported by substantiai compe~ent 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 th~t was adopted by CURB, and utilizing a 9.35% cost of equity, would increase CURB's net revenue requirement from $50.80 niiHion 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 tl;ie 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* char~es 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 BehalfofCURB.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 I I.
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* of Kansas, 28 Kan. App. 2d -313, 316 (2000).
33
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 otder 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
.uti*1*1t1es.
. 167 Specifically, 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 s~ch 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 aseparate part of this order.
166 Cent. Kansas Power Co. v. State Corp. Comm 'n, 221 Kan. 505, 511 ( 1977).
161 Id.
168 Int'/ Motor Rebuilding Co. v. United Motor Exch., Inc., 193 Kan. 497,499 (1964).
169 K.S.A. 66-10 I b. .
34
- 93. The Parties and the Commission complied with all procedural rules within this*
.I docket. The Parties and the Commission complied with the procedural schedules, the issuance of I
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 thf 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 c,omplies with applicable law.
po Cent. Kansas Power Co., 221 Kan. at S 11.
171 See supra Part LC.
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 cons1.d er. 11s .
- 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.
9~. 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 Citizens' Util. Ratepayer Bd v. State Corp. Comm 'n ofState, 47 Kan. App. 2d 1112, 1131 (2012).
174 Kansas Gas and £lee. Co., 239 Kan. at 488.
175 Glass S&ATestimony at 15.
176 Greenwood S&A Testimony at 2.
177 Id. at 16.
178 Jd.
119 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 ~ompels 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 obligatfons, and the desire of the r~tepayer 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
, reasona bl_e ;rom c. the v1ewpomt
. . . 187 As M
. of the s1gnatones. . r. Grady postu1ates, 1"f 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.
IOI. Ms. Crane testified in 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, redu.ced 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 ofreasonableness 1s used to determine whether a particular rate .is contained within an "elusive range of reasonableness in calculating a fair rate of retum." 193 The Commission acts within the discretion granted to it when it searches for and finds an in-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 Id.
189 Crane S&A Testimony at 13.
190 Id.
191 ld. at 13-14.
192 Id. at 14.
193 Kansas Gas and Elec. Co., 239 Kan. at 490.
194 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
. I
- 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 wil.1 result in rates that are notunduly 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'~ 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 alfordable 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 impr~ve 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 re~sonableness 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.
Gre_enwood also testified that th~ rate specific classes customers would pay, as proposed by the S&A is supported by the numerous c;:lass 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 ld. at 17-18.
40
programs and reductions in prices* for renewable investment options. 197
- Regarding spec.ific 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 un~eliable 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.
201 Id.
202 Id.
20; Id.
2
().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, Westar' s requested revenue is reduced to a level that Westar still finds reasonable while at the same time decreasing the proposed cost customers 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 207 financial obligations while providing sufficient and efficient service. The Commission concurs with Mr. Grady's assessment.
111. Ms. Crane also testified that approval of the S&A is in the public inte~e~t. 208 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. Cr~e co~cluded 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 mariner 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 P1;Udently incurred expenses and continue to make reliability enhancements to Kansas' electric grid. Based upon the wide ranging support and l~ck of opposition to the S&A, as well as how .the S&A will 'affect ratepayers if approved, the Commission is confiden.t in
- finding that approval of the S&A is in the public interest.
III. Abbreviated Rate Case 113. The Joint Movants request Westar be granted preapproval to file an abbreviated rate case. . Pursuant to K.A.R. 82-1-231 (b)(3 ), a utility proposing to change rates within 12 mqnths after <J. 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 method 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. 82-1-231 (b)(3)(A).
213 K.A.R. 82-l-231(b)(3)(B).
44
V. Fi1_1dings 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 competen~
evidence as filed in this proceeding.
123. The Commission finds that approval of the S&A as amended is in the public interest.
I* 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 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. 66-1 l 7(c) in terms of suspension periods, is permitted by KS.A.66-117(b) as Westar would have tc:i 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:
I ,
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 jurisdictiQn ,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 Dated: SEP 2 4 2115 REV/DLK Secretary to the Commission ElVIAILED
/
SEP 2 4 2015 215 K.S.A. 66-l 18b; K.S.A.77-529(a)(l).
47 I
I
CERTIFICATE OF- SERVICE 15-WSEE-115-RTS I, the undersigned, certify that the true copy of the attached Order has been se~ed to the following parties by means of Electronic Service on __S_E_P_2_4_Z_0_15____
JAMES G. FLAHERTY, 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 COUNSEUVP REGULATORY .
BOEHM, KURTZ & LOWRY AFFAIRS 36 E SEVENTH ST STE 1510
.Fax: 513-421-2764 KANSAS CITY, MO 64108 jkylercohn@bkllawfirni.com* Fax: 816-511-0822 andy.zellers@brightergy.com GLENDA CAFER, ATTORNEY TERRIPEMBERTON,ATTORNEY CAFER PEMBERTON LLC CAFER PEMBERTON LLC 3321 SW6TH ST 3321 SW6TH 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 SW ARROWHEAD RD 1500 SW ARROWHEA6 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 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 SUITE 210 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.peterso*n201 O@gmail.com JOHN GARRETSON, BUSINESS MANAGER JOHN R. WINE, JR.
IBEW LOCAL UNION NO. 304 410NE43RD 3906 NW 16TH STREET TOPEKA, KS 66617 TOPEKA, KS 66615 Fax: 785-246-0339
- johng@ibew304.org jwine2@cox.net DUSTIN KIRK, ASSISTANT GENERAL COUNSEL MI.CHAEL 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: 785-27.1-3354 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 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 7400 W 110TH ST STE 750 KANSAS CITY, MO 64112 OVERLAND PARK, KS 66210-2362 Fax: 913-451-6205 Fax: 913-661-9863 lhagedorn@polsinelli.com jim@smiz_ak-law.com MARTIN J. BREGMAN, ATTORNEY .DUSTIN BASHFORD, MANAGER - SYSTEM DESIGN STINSON LEONARD STREET LLP TALLGRASS PONY EXPRESS PIPELINE, LLC 1201 WALNUT ST STE 2900 370 Van Gordon Street KANSAS CITY, MO 64106 Lakewood, CO 80228 Fax: 816-691-3495 dustin.bashford@tallgrassenergylp.com marty.bregman@stinsonleonard.com Stefan Evanoff, VICE-PRESIDENT, PIPELINE ADAM SCHICHE, SENIOR ATTORNEY MANAGEMENT TALLGRASS PONY EXPRESS PIPELINE, LLC TALLGRASS P.ONY 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 THQMPSON & KNIGHT LLP THOMPSON & KNIGHT LLP 98 SAN JACINTO BLVD STE 1900 98 SAN 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, ATTORNEY . SAMUEL D. RITCHIE, ATTORNEY TRIPLETT, WOOLF & GARRETSON, LLC TRIPLETT, 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 201N WATER 201 N WATER ST RM 405 WICHITA, KS 67202 WICHITA, KS 67202-1292 Fax: 316-973-2150 tpowell@usd259.net dbanks@us_d259.net KEVIN K. LACHANCE, CONTRACT LAW ATTORNEY MATTHEW DUNNE, GENERAL ATTORNEY 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 *c1TY, MO 65101 TOPEKA, KS 66601-0889 Fax:573-635-7523 cindy.s.wilson@westarenergy.com david.woodsmall@woodsmalllaw.com DeeAnn Shupe
.BMAILED SEP 2 4 2015
Enclosure VIII to WM 19-0008 I'
Order Approving Unopposed Stipulation and Agreement (15-WCNE-093-GIE)
(10 pages)
2015.03.24 14:03:41 Kans.35 CorFor.atiori Comri'!ission 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 )
Decominissioning Cost Study as Provided by )
- Wolf Creek Nuclear Operating Corporation in )
Accordance with the Commission's Order in ) Docket No. l 5-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 Decommission}ng Cost Analysis for the Wolf Creek Generating Station in accordance with the Commission's December 9, 1992 Order in Docket No. i63,561-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) 1 project at Wolf Creek as part of the, triennial decommissioning cost study filings.
1 See Docket No. 13-WCNE-204-GIE, Order Closing Docket, Ordering 'I! A(June 13, 2013).
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 detennining 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, 201S, 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 3
advised the other parties that it does not oppose the. Stipulation. The Preheating Offiter 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. l 0, 2015) (Joint Motion).
- 3 Joint Motio.n, p.2.
2
approved the motion to .convert the evidentiary hearing to a settlement hearing on February l l, 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 acc01.~nt 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 Stipµlation 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' Decoinmissionirig 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 Aug*ust 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 Conven 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 iin.d 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:
- i. 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.
- 11. On or before September 1, 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 6
policy reasons for its decision if it is an exercise of its discretion. Any findings of fact must be based exclusively upon the evidence of record in the adjudicative proceeding and on matters officially noticed irr the proceeding. 7 Agency action must be based upon evidence that is 8
substantial when viewed in light of the record as a whole.
A. Standard of Review
- 11. The Commissi.on 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
'1 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 10 establish just and reasoQ.able rates.
B. Evafllation oftfte Stipulation
- 13. The Commission will consider the Stipul!}tion 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.77-62l(c)(7), (d).
9 Krantzv. Univ. of Kan., 271 Kan. 234, 241-42 (2001).
1
°Citizens' Utility Ratepayer Board v. State Corp. Comm 'n, 28 Kan.App.2d 313, 316 (2000).
5
J. Is the Stipulation supported by substantial evidence in the 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 tl.ie 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 $765,060,000 and the escalation rate of 3.15% agreed to in the Stipulation are supported by substantial competent evidence in the record.
- 16. Having reviewed the evidence in the record, the Commission concludes that
- substantial evidence is present in the record a$ a whole to support approval of the Stipulation.
The Commission finds evidence in the record as a whole establishes the Stipulation is reasonable and shpuld be approved-in its entirety.
- 2. Will tl,e Stip11lation result in just and reasonable rates?
- 17. Every electric public utility in Kansas is required to provide reasonably efficient 11 and sufficient service and establish just and reasonable rates.
- 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 M~vants state 11 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 h1 rates later should not 14 cause such rates to become unjust or unreasonable.
- 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 tJ,e results of tJ,e Stipulation in tlzf! public interest, including tire interest oft/re customers represented by any party not consenting to tlze agreement? *
- 20. The Joint Movants agree the terms of the Stipulation are in the public interest and 15 should be approved by the Commission. 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; arid 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 art 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-16 consuming proceedings.
- 21. In reviewing the Stipulation presented by the parties, the Commission has considered that the agreed-upon and stipulated decommis~ioning 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.
15 /d., 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 Commissi~:m finds that the Stipulation is supported by substantial, COII!petent evidence, is in the public interest, and will resuhinjust 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;
- B. This Order shall be electronically serve~ 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 par:ties 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 Date: _ _MA_R_2_4_2D_15_*__
Ne~sa Thomas EMAELED Actmg Secretary
8
MAR 2 4 *2015 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 20\5
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 IX to WM 19-0008
).I I',
Order Approving Stipulation and Agreement (File No. E0-2018-0062)
(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 23rd day of January, 2018.
In the Matter of Application of Kansas City Power )
& Light Compa.ny for Approval of the Accrual and' .) File No. E0-2018-0062 Funding of Wolf Creek Generating Station )
Decommissioning Costs at Current Levels. * )
ORDER APPROVING STIPULATION AND AGREEMENT*
Issue Date: January 23, 2018 Effective Date: February 22, 2018 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 Septembe.r 1, 2017, KCP&L filed an application pertaining to Wolf Creek asking the Commission to: (a) find that the 2017 cost study and 2017 funding analysis satisfies the requirements of 4 CSR 240-:3.185(3); and (b) approve the continuation of the annual 1
accrual at the current level of $1,281,264.
1 4
In filing its application, KCP&L did not comply with the 60-d~y notice provision of CSR 240-4.017(4), which requires advance notice of an intent to file a new case before the Commission. In the stipulation and
Staff and KCP&L filed a non-unanimous stipulation and agreement on January 5, 2018. 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 oppo~ed 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, the 2017 Cost Study, and the Funding Analysis;
- Find that KCP&L's 2017 Cost Study and Funding Analysis 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
$1 ,281,264;
- Find, in order for the decommissioning fund to retain its qualifiedtax status, that
, the annual decommissioning costs for Wolf Creek, inclusive of the Independent Spent Fuel Storage Installation (ISFSI), are included in KCP&L's current Missouri cost of service and are reflected in its current Missouri retail rates for ratemaking purposes; and *
- Authorize KCP<$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.
agreement, KCP&L requests a waiver of that requirement, presenting a verified statement that it had no communication with the Office of the Commission within the 150 days before it filed the application, thus providing good cause for the requested waiver. The Commission will grant the requested waiver.
2
Having considered the 2017 decommissioning cost study for th~ Wolf Creek Generating Station and the stipulation and agreement, both of which will be received into evidence, the Commission determines that the stipulation and agreement should be approved. In doin.g so, the Commission finds that KCP&L's 2017 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 afthe current level of $1,281,264. The Commission also finds 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.
THE COMMISSION ORDERS THAT:
- 2. The signatories shall comply with the terms ofthe stipulation and agreement.
- 3. . The stipulation and agreement and Kansas City Power & Light Company's 2017 Cost Study and Funding Analysis 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.
I
- 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.
3
- 6. Kansas City Power & Light Company's request for waiver of the 60-day notice requirement of 4 CSR 240-4.017(1) is granted.
7, This order shall):>ecome effective on February 22, 2018.
- i
- 8. , This file shall be closed on February 23, 2018.
BY THE COMMISSION Morris L Woodruff Secretary Hall, Chm., Kenney, Rupp, Coleman, and Silvey, CC., concur.
Woodruff, Chief Regulatory Law Judge 4
Enclosure X to WM 19-0008 Non-Unanimous Stipulation and Agreement (File No. E0-2018-0062)
(17 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. E0-2018-0062 Accrual and Funding of Wolf Creek Generating )
Station Decommissioning Costs at Current Levels )
NON-UNANIMOUS STIPULATION AND AGREEMENT
("Agreement") to the Missouri Public Service Commission ("Commission'}. 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 RSMo 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. Co,r;~'n., 585 S.W,.2d 41 (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 fun9ing level or accrual rate of the trust J
fund when deciding matters related to the rates and charges associated with that fund.
1 All statutory references are to Revised Statutes of Missouri 2016, unless otherwise noted. Section*
393.292 was enacted by the Missouri Legislature in Laws 1989 and has not been amended.
1
Further, Section 393.292 gives the Commission authority to adopt rules and regulations governing the procedures assodated with these tariff changes as well as to ensure that the amounts contained in the trust funds will .be neither "greater nor less~r 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 C(?mmission co_st 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 a~ 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 Powe_r & 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.
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 2
If decommissioning financial assurance is provided by an external sinking fund, 10 CFR 50.75(e)(1)(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 life, the shutdown date used in the 2011 and 2014 Studies is 2045, the year in which Wolf Creek's operating licen!?e now expires.
2
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). Th.e 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 decommissioning cost accrual would be addressed in the context of the then upcoming rate case (now known as File No. ER-2010-0355).
3
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 Funding 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 projectt3d 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 DE CON 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 Non-Unanimous Stipulation And Agreement, which
,I Public Counsel did not oppose. As part of the Non-Unanimous 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 4
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 On August 29, 2014, K~P&L filed in File No, E0-2015-0056 an Application for Approval of the Accrual and Funding of Wolf Creek Gen~rating Station 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 2014 Study, the final shutdown date of Wolf Creek was projected to occur in 2045 .
. The calculations set forth in the 2014 Study were performed in a manner consistent with previous filings. KCP&L's 2014 analysis confirmed the adequacy of the annual funding level of $1,281,264 (Missouri jurisdictional amount), given the 2014 Study's then current .
prediction of decommissioning costs of $765.060 million for the DEGON decommissioning option under what KCP&L believed were a reasonable set of economic, fin~ncial, and investment assumptions. Consequently, KCP&.L did not seek any changes to its funding level. KCP&L and the Staff entered into a Non-Unanimous Stipulation And Agreement,*
which Public Counsel did not oppose.
As part of the Non-Unanimous Stipulation And Agreement in File No. E0-2015-
, 0056, KCP&L and the Staff agreed as follows:
- 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 5
- 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.
THE 2017 STUDY Pursuant to 4 CSR 240-3.185(3), on September 1, 2017, 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 Generating Station Decommissioning Cost Estimate Update for September 1, 2017 ("2017 Study"). The 2017 Study, with the date August 2017 on its cover, was prepared for the Wolf Creek Nuclear Operating Corporation ("WCNQC") by TLG Services, Inc. (TLG"), a consulting engineering firm based in Bridgewater, Connecticut. 3 The TLG an.alysis relies upon site-specific, technical information from a TLG evaluation prepared in 2014, updated to reflect current assumptions pertaining to the disposition of the nuclear station and relevant industry experience iri undertaking such projects. Costs are represented in 2017 Dollars.
For the purposes of the 2017 Study, the final shutdown date of Wolf Creek is projected to occur in 2.045. The 2017 Study shows the decommissioning cost estimate to be $813,733,000 million in 2017 Dollars for the DEGON decommissioning option. TLG 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 irJ previous KCP&L and Union Electric Company decommissioning cost studies.
6
examined two decommissioning options: (a) DECON, 4 and (b) SAFSTOR. 5 Both.
alternatives are acceptable to the NRG. KCP&L's Schedule B ("2017 Funding Analysis")
to the Application indicates that under current assumptions the present annual trust fund contribution of $1,281,264 is suffident to meet thE3 estimated DEGON decommissioning option within $263,000 which is less than 0.40% of the Missouri jurisdictional share of 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 2017 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.
The 2017 Study by TLG includes KCP&L's share of thE3 cost for decommissioning*
the Independent Spent Fuel Storage Installation ("ISFSI") at Wolf Creek .. KCP&L's 47%
share of the $6.69 million is $3.14 million (MO and KS) identified in the current decommissioning cost analysis [Document Wll-1741-001, Rev. 0, Table C, cost element 2d.2.4] prepared by TLG Services, Inc., elated August 20*17. 6 The ISFSI will be constructed on the Wolf Creek site to hold the spent nuclear fuel assemblies (high-level 4
DEGON assumes decontaminating and decommissioning immediately foHowing conclusion of power operations in 2045. Work is anticipated to be completed by ~053. DEGON 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 2017 Dollars is
$813,733,000. .
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 NRG. This process is anticipated to be completed by 2106. Total estimated cost to decommission in 2017 Dollars is $1,093,117,000.
6 Since the design for decommissioning has not been selected, the $6:69 million amou*nt should be considered a representative decommissioning cost included within the DEGON and SAFSTOR estimates.
(See page 50 of 139 of TLG Services 2017 Study.)
7
radioactive waste). The Department of Energy ("DOE") has partially breached a contract with KCP&L, under which KCP&L customers had, until recently,* been paying fees in rates, to remove, transport, and dispose of at the Nevada - Yucca Mountain repository site.
Until the DOE performs under that contract, the spent n_uclear fuel assemblies will need to be stored onsite in the ISFSI with a portion stored in the spent fuel pool until decommissioning.
Among other things, the 2017 Funding Analysis is based on capital market assumptions dated July* 1, 2017 from KCP&L's pension consultants, Willis Towers .
Watson as agreed in the Non-Unanimous Stipulation And Agreement approved in File No. E0-2012-0068, and a decommissioning cost escalation rate based on inflation assumptions also from Willis Towers Watson dated July 1, 2017 in order to provide consistency with the capital market assumptions .
. In its Application, KCP&L requests the Commission: (i) find that the 2017 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* 1evel 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 fili~g, 8
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 j,urisdictional 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 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 decolllmissioning 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. 7
- 2. On SeptembE:ff 1, 2017, KCP&L filed its Application along with the 2017 Study. The Signatories request that the Commission recognize in its Report and Order for this case that KCP&L's Application and the 2017 Study meet the requirements of 4 CSR 240-3.185(3).
7 Case/File Nos. ER-2007-0291, ER-2009-0089, E0-2009-0072, ER-2010-0355, ER-2012-0174, and ER-2016-0285.
- 9
- 3. The 2017 Study estimates the decommissioning cost for the DEGON alternative to be $813,733,000 in 2017 Dollars, which is 6.36% higher than the 2014 estimate of $765,060,000 which represents approximately a 2.08% annualized escalation
- rate over the 3-year period. The 2017 Study inclupes KCP&L's share of the estimated cost for decommissioning the ISFS! under the specific assumptions in the TLG Services 2017 Study. ,,
, 4. ISFSI funds recovered from the DOE in connection with decommissioning of the ISFSI will be used to offset the costs of decommissioning the ISFSI.
- 5. Pursuant to 4 CSR 240-20.070(12), excess trust funds from the costs of decommissioning the*Wolf Creek Generating Station and the ISFSl.are to be reimbursed to the ratepayers through the ratemaking process.
- 6. 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 and the ISFSI.
- 7. The Signatories agree that it is reasonable to use capital market return expectation information provided by Great Plains Energy's pension p*lan 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 10
. market return expectations or the Gommission finds in a contested case that different
- ;s'ource and/or meth9dology for capital market return expectation are more appropriate.
- 9. Annual Missouri retail jurisdictional decommissioning costs, inclusive of the .
ISFSI, 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 Re.port and Order and note that this finding is required in order for the decommissioning fund to retain its qualified tax status.
- 10. . 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 asubsequent rate proceeding.
- 11. The Signatories agree that KCP&L shall continue to record and preserve Wolf yreek 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.
- 12. To the extent the Commission belieyes that 4 CSR 240-4.017 applies, KCP&L requests a waiver for good cause of this rule. KCP&L attaches as Exhibit A, a verified statement that it had no communication with the Office of the Commission within the prior 150 days to the filing of the Application in File No. E0-2018-0062 regarding-any
\.J substantive issue likely to be in this case.
- 11
- 13. Except as explicitly agreed otherwise herein, none 0f the Signatories to .
this* Agreement shall be deemed to have approved or acquiesced in any question of ,:'.f.-:.
Commission authority, decommissioning methodology, ratemaking principle, valuation methodology, cost of service methodology or det~rmination, depreciation principle or method, rate design methodology, cost allocation, cost recovery, or prudence that may underlie this Agreement or for which pro_vision is made ir'.1 this Agreement.
- 14. 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 accordancewith Sectio!l 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 suggestions or memoranda, testimony or exhibits that may have been offered or received in.support of or in opposition to this Agr~ement shall thereupon b_ecome 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 .
. .15. ~o 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.
12
. 16. 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 Staffs 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.
- 17. 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 Staffs 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.
- 18. 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 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 13
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.
- 19. The 2017 Study shall be received into evidence.
- 20. 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.
21; The provisi(?nS 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.
- 22. 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 14
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, the 2017 Study (Schedule A to the Application), and the Funding Analysis (Schedule B to the Application); *
- 3. . Finding that KCP&L's 2017 Study and Funding Analysis satisfy 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, inclusive of the ISFSI, 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.
15
Respectfully submitted, 14' SfeQe# "O~ .
RogerW. 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
(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 5th day of January, 2018.
- Counsel for Kansas City Power & Light Company 16
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. E0-2018-~062 Accrual and FundingofWolfCreek.Generating )
Station Decommissioning Costs at Current Levels )
VERIFIED DECLARATION OF LOIS J, LIEtHTI Lois J. Liechti, being first duly sworn on his oath, states:
- 2. Pursuant to the requirements of 4 CSR 240-4.01 ?(D), I hereby certify, to the best of my knowledge, information, and belief, that KCP&L personnel have had no communications*
with the office of the Missouri Public Service Commission within the prior one hundred fifty (150) days of the filing of the Application in File No. E0-2018"'0062 regarding any substantive issues likely to be in this case.
~,~
01s . 1e~ rrector - egu atory Kansas City Power & Light Company arrs Subscribed and sworn before me this s.ftA... day of January, 2018.
My commission expires: . tfj 2-CJ/ ,u:, 1-/ ANTHONY R WESTENKIRCHNER Notary Public. Notary Seal State of Missouri Platte County Commission# 17279952 My Commission Expires April 26. 2021 1
Exhibit A Paae 1 of 1
Enclosure XI to WM 19-0008
)
Direct Testimony of Adam H. Gatewood (June 11, 2018)
(104 pages)
20180611150514 Filed Date: 06/11/2018 State Corporation Commission
Joint Application of Westar Energy, )
Inc. and Kansas Gas & Electric ) Docket No.
Company for Approval to Make ) 18-WSEE-328-RTS
. Certain Changes in Their Charges for )
Electric Service )
. DIRECT TESTIMONY PREPARED BY Adam H. Gatewood UTILITIES DIVISION KANSAS CORPORATION COMMISSION .
June 11, 2018
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS .
I Table of Contents Executive Summary .......................................................................................................,................... 2 Decommissioning Trust Annual Accrual. ................... ,................................ :.................................. .3 Rate of Return Analysis ................................................................................................................... .8 Capital Structure ................................... ,.............. ,....... , ................................................................. 10 Cost ofDebt .............................................. :.................... ,............................................................... 11 Cost of Equity Analy.sis ......................................_. ... :.....................................*................................. 12 Standards for a Just & Reasonable Rate of Return ................. :....................................................... 26 KCC Proxy Group ............................................................................................................ :............... 29 Return on Equity Analysis .................................................................. ..'......................................... 34
' I
- Discounted Cash Flow Model. ..... ,............................................................................... ;................. 37 Forecasted Growth Rates for the DCF Model.. ............................................................. 39 DCF Results ..................... .- ..- ..............*............................................ ,..................... ,.......... 46 Internal Rate of Return (IRR) Analysis ....................................................... :................. 49 Capital Asset Pricing Model (CAPM) Analysis .. ,......................................................................... 51
- 1. Q, Would you please state your' name and business address?
2 A. My name is Adam H. Gatewood. My business address is 1500 Southwest Arrowhead 3 Road, Topeka, Kansas, 66604.
4 Q. Who is your employer and what is your title?
.5 A. I am employed in the Utilities Division of the Kansas .Corporation Commission as a .
6 Managing Financial Analyst.
7 Q. What is your educational and.professional background?
8 A.
- I graduated from Washburn University with a B.A. in Economics and a Masters of Business 9 Administration. I have filed testimony on cost of capital and related financial issues before 1
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 the Commission in more than 120 proceedings. I have also filed testimony on cost of 2 capital issues before the Federal Energy Regulatory Commission in natural gas pipeline 3 and electric transmission dockets.
4 Executive Summary 5 Q. What issues are you testifying to in this Docket?
6 A. My testimony addresses the annual accrual for Westar's nuclear decommissioning trust 7 (NDT) and the rate of return used to calculate Westar' s revenue requirement.
8 With respect to annual accrual for the NDT, I recommend that an annual accrual of 9 $7,793,500 based on the decommissioning methodology advocated by Staff witness Leo 10 Haynos. I also recommend that the Commission create a faGtor in Westar's (WR's) Retail 11 Energy Cost Adjustment (RECA) to recognize changes to the annual 'accrual that occur 12 outside of general rate cas.es.
13 With respect to the rate of return, I recommend that the Commission adopt a rate of return 14 of 7.06% that incorporates the 9.30% return on equity set out in the Non-Unanimous 15 Settlement approved in l 8-KCPE-095-MEE- (18-095). My analysis in this Docket provides 16 substantial evidence that 9.30% is a fair and reasonable .return for both shareholders and 17 ratepayers and, therefore, it should be adopted by the Commission to set Westar's revenue 18 requirement.
19 Q. What documents* did you review to prepare your analysis?
20 A. In preparing my rate of return analysis and recommendation, I reviewed the following 2
Direct Testimony of Adam H. Gatewood Docket No.18-WSEE-328-RTS 1 documents directly connected to this Docket: 18-WSEE-328-RTS (18-328) Testimony&
2 Application;18-095 Non-Unanimous S&A; responses to data requests issued by KCC 3 Staff and other parties; cost of capital work-papers provideq in response to KCC data 4 request 85; and updates to Section 7 (cost of capital) provided in response to KCC data 5 request 159. In preparing my recommendations for Westar's annual accrual, I reviewed 6 the 18-107 Testimony and Application; the testimony of Leo Haynos filed in 18-WCNE-7 107-GIE (18-107); responses to KCC data requests 126, 156, 157, and 158 in Docket 18-8 328.
9 Decommissioning Trust Annual Accrual 10 Q. Please summar~e your recommendation for Westar's annual ~ccrual.
11 A. With respect to Westar's NOT, I recommend an annual accrual of $8,694,000 if the 12 Commission adopts the SAFESTOR methodology, or $7,793,500 if the Commission 13 adopts the DECON Alternative with Long-Term Spent Fuel Management methodology.
14 In addition, I recommend that the Commission include a variable in Westar' s RECA to 15 account for any difference between the NDT annual accrual in base rates and the amount 16 set by any subsequent decommissioning cost review.
17 Staffs recommendation to ,recognize the increased costs associated with spent fuel 18 management results in an increase in the annual accrual. Staff witness Leo Haynos 19 explained in his18-107 Direct Testimony that the U.S. Department of Energy's inability 20 to accept spent fuel for final disposal brings on the necessity for managing the spent fuel 3
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 at the reactor site for an indefinite period of time. 1 His recommendation recognizes those J
2 additional costs. Wolf Creek owners are not paying a fuel disposal surcharge 2 to DOE at 3 this time. 3 That surcharge was more than the increase in the annual accrual that Staff 4 recommends. 4 At this time, with the suspension of that surcharge, recognizing the costs of 5 managing the spent fuel is not an increase to consumers. It is an issue that is in flux, and a 6 solution could be many years in.the future, but regardless of the solution, there will be costs 7 incurred to manage and dispose of spent fuel. It is Staff's view that it is in all parties' 8 interest to accrue funds for those costs over the life of the plant.
9 Q. Describe the triennial review process of the decommissioning cost estimates.
- 10 A. The triennial review is .done in two phases. In phase one, the Commission reviews the 11 decommissioning cost study, selects the decommissioning methodology, and decides on 12 the inflation rate to apply the decommission cost estimate. By selecting the methodology, 13 the Commission is selecting a cost estimate that is in current-year dollars. The inflation 14 rate is necessary to escalate those costs to the year they will occur. The .sum of those 15 inflated costs is the amount that the owners must accumulate in their respective NDTs.
16 Phase two determines the annual accrual necessary to fully fund the owner's NDT.
17 Q~ What was decided in phase one?
18 A. At the time I flied testimony in this Docket on June 11, 2018, there is no decision by the 19 Commission m. phase one. My recommendation m phase two is based on the 1
18-WCNE-107-GIE; Direct Testimony of Leo M. Haynos; May 15, 2018; p. 15.
2 DOE surcharge of 1 mil/kWhr to fund the final disposal of spent fuel..
3 18-WCNE-107-GIE; Response to Staff Data Request 21.
4 18-WCNE-107-GIE; Response to Staff Data Request.21. (Estimated DOE 2017 surcharge for Westar is $4.7m).
4
Direct.Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 recommendations by Staff witness Leo Haynos in phase one. Staff witness Leo Haynos
\
2 recommends the DECON Alternative with Long-Term Spent Fuel Management1 3 (DECON-LTSFM). As an alternative, he recommends the SAFESTOR method as it also 4 provides a cost estimate that recognizes the spent fuel storage issues. If the Commission 5 adopts a different methodology in the 18-107 Docket, I will file additional testimony to 6 reflect the Commission's decision.
7 Q. Please explain Staff's rationale for introducing* the NDT variable to the RECA.
8 A. Adding an NDT variable to the RECA will ensure that Westar collects through rates the 9 amount that it deposits in its NDT account. Staff witness Justin Grady will explain the 10 mechanics of the adjustment factor in the RECA formula. Commission Orders in 1984.
11 established a three-year cycle for Wolf Creek's decommissioning cost studies. In reality, 12 this three-year review cycle may not sync up with each owners' rate cases, thus the annual 13 accrual collected in base rates may not match up with the Commission's latest adopted cost 14 . NDT funding level. The five-year moratorium in the 18-095 Agreement highlights the 15
- timing miss-match that we want to avoid.
16
17 A. Westar prQposes to keep its NDT annual accrual unchanged at $5,772,700. This 18 calculation encompasses forecasted asset returns published by J.P. Morgan Asset 19 Management (2017); the current NDT balance of $222,277,308 (net of tax liabi~ities) at 20 September 30, 2017, using the DECON decommissioning methodology; and an inflation 21 rate of 2.91 % to escalate costs to future years.
5
Direct Testimony of Adam H. Gatewood Docket No. l 8-WSEE-328-RTS 1 Staffs recommendation is higher than Westar's proposal due to:. 1) lower forecasted 2 returns; and 2) a change to the decommissioning methodology from DECON to DECON-3 LTSFM which is a longer and costlier decommissioning process. The decommissioning 4 methodology and the inflation rate are subject to Commission determination in the 18-107 5 Docket.
6 Q. Why are you using a lower return in your calculation than the return used by Westar 7 witness McGrath?
8 A. We are using the same source for the forecasted return data, but Westar relied on the data 9 published for 201 7 and my calculations use the 2018 edition, which reports lower expected 10 returns than the 2017 forecasts. We are both using Long-Term Capital Market 11 Assumptions (LTCMA) published by J.P. Morgan Asset Management (JPMAM) as our 12 source for expected returns over the long-run (more than ten years) for various asset 13 classes. The following table shows the 2017 and 2018 forecasts for the asset classes used 14 in the NDT and highlights the lowered forecasts.
J.P. Morgfill Asset_ Managflllent ___ _
__ Long~Term_Capital Market_Assump)ions ___ _
2017 2018
_ Equities-Large Cap_ 7.63% 6.41% - -/...-
!Equities-Small Cap 8.67% 7.35%
- )iq~iti;;~futer~ati~~al (EAFE)- 7.61%
_:c::~_r~ B_9nds__ _ __ ___ _ _ _ :_ 3.44% _ -~ __ 3.§7%
High Yield Bonds . , 6.13% 1 5.59%
- Real Es~t~ --- I : 7.32% r 7.42% 1
---i~----------===--_-_--_*
lfash & Equivalents -_-_--_-_-_-_-_-;___* I -----'-,_____
2.00% I ____2.00% -i--
- I
!--- -----~-------- -------- ___ 1 ___ --- --- --- ~
ihttps://am.jpmorgan.com/us/institutionaV2018-long-term-capital-market-assumptions 15 * '
16 Q. Is ~MAM's publication a reasonable source for these types of forecasts?
6
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 A. Yes, J.P. Morgan's forecasts in this publication are consistent with forecasted returns by 2 other money management firms and reflect the expected returns of institutional portfolio 3\ managers.
4 Q. Did you quantify the impact of the lower forecasted returns?
5
- A. Substituting the lower 2018 forecasts for the 2017 forecasts in Westar's work-papers 6 *increases the annual accrual from $5,772,700 to $6,441,000; a $668,300 increase using the 7 DECON methodology. Thus, a majority of the increase is associated with the added costs 8 of the DECON- LTSFM or SAFESTOR methodologies.
9 Q. Historically, what has Westar's NDT earned?
10 A. I performed an internal rate of return analysis on Westar's deposits to its NDT from 1986 11 through the present. Over that time period, Westar's NDT experienced an annual return of 12 5.68%.
13 Q. How does the NDT's historic return compare to the forecasted return?
14 A. The 2018 forecasted returns, using Westar's proposed portfolio structure and the DECON 15 methodology's projected cash-flows, indicates a return of 3.18% for the time period of 16 2017 through 2053. The difference reflects changes in lower expected returns in the future 17 as compared to the past occurring across all asset dasses, as well as a progressively more .
18 conservative portfolio as we near the decommissioning date. Virtually all of the economic 19 and financial literature point to this same scenario playing out in the capital markets.
20 Investors can expect lower returns in the future relative to the past due to lower inflation 7
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 and slow real economic growth; each of these variables put downward pressure on expected 2 returns.
3 Q. How did you calculate the annual accrual amount?
4 A. My calculation appears in Schedule AHG-1, which assumes the DECON-LTSFM 5 methodology, an NDT balance (net of incom:e taxes) as of March 31, 2018, and forecasted 6 returns from the 2018 edition of the JPMAM-LTCMA. The blended returns of the portfolio 7 across time appear in Schedule AHG-2. The annual accrual is the amount that equates the 8 cash in-flows (annual accrual plus returns on the portfolio) to the cash out-flows (the 9 decommissioning expenses). The combination of variables that I discussed result in an 10 annual accrual of $7,793,500 for Westar's NDT to meet its future obligations.
11 Rate of Return Analysis 12 Q. Please discuss the framework of Staff's rate of return (ROR) analysis in this Docket.
13 A. Staffs ROR analysis in this Docket is, in part, a continuation of the analysis that Staff 14 performed in the 18-095 Merger Docket. These two Dockets are made interdependent by 15 the 18-095 S&A, 5 where signing parties committed to supporting an allowed return on 16 equity CR.OE) of 9.30% 6 in this Docket for Westar, as well as the 18-KCPE-480-RTS 17 Docket for Kansas City Power & Light. On May 24, 2018, the Commission approved the 7
18 Non-Unanimous Stipulation and Agreement filed in the Docket 18-095 S&A.
5 Non-Unanimous Settlement Agreement; 18-KCPE-095-MER; filed March 17, 2018.
6 Non-Unanimous Settlement Agreement; 18-KCPE-095-MER; filed March 17, 2018; at paragraph 32, iv, l; p. 15.
7 Order Approving Merger; 18-KCPE-095-MER; Issued May 24, 2018.
8
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 Q. With regard to Westar's ROR, what are your findings and recommendations?
2 A. The following table summarizes my recommended ROR and the components of the 3 calculation.
J_ I _J_ I _________ -~-
1 Staff Recommended Rate of Return _____ ',_
_!!_pclated Capital Stru-cture via KCC DR#1_59 & 1-8-095 S&A +-
- F March 31, 2018 ,
r:--- ---------- -: ------ '---r 1
~
- Weight l
- l I
--- - - - - - - - -- - - - - - - --r----
Cost
. J Weighted-i
- Cost
-T-I I
jLong-termDebt ------~
- 48.33~-- -~- 4.68%1 _____ 2.26% ,__
lfo=mmonEquity ___i____ __Jl.24%1 ______ :___9__ l~L ______ 4.77%
,Post.1970 ITC I 0.43%i 7.06%1 0.03%
-l
,~-------~-------------;-
I 1 1
--- __ ! ~
O(;Ofn 1 4- Source: KCC DR#l59 I ______ __ ___ + __________ J__ ______ _: __ _
4 1 1- f I 5 As a point of comparison, Westar's Application is based on the following ROR.
I !
- 1 - - - - - - - - - - - - - ~ - - - - ~ - - - ~ ~ - - - - ---- ---- - ~-
I
- -- ------ Westar Energy -- Rate
- ----of Return
- Proposed Rate of Return in Section 7 of Application
__ : Test Year_Ended_Ju~ 30, 2017 Updated to September 30, 2017
' (
I - - ----i------ - _ - -, --weighted *
---,--- -- - :- -Weight- ' Cost - ,- - Co~t --- :-
- ILong~term Debt __: ___ _L ___ __i~2~L- _____ 4.65% :__________ 2.24% i
__ jCommonE_guitx_____ ;_ ----------~l.36r~--- _9.8~ __ _ ~-Q~ro: __
iPost 1970 ITC i 0.44%, - .7.33%, - 0.03%!
--- -: - ~ - - -------
l _- : -
~----- --- -
7.33%1
______ '.J -
__ Source: 18-WSEE-328-RTS; Section 7 _ --------~---- ___________ !_
I , .
- I 6 1 7 Setting the rate of return requires decisions on the cost of debt, the cost of equity, and the 8 weight of each in the utility's capital structure. Staff is preparing its revenue requirement 9 - incorporating an update to March 31, 2018, account balances from the September 31, 2017, 9
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE~328-RTS 1 balances used in the Application. The ROR that I recommend is based on the updated 2 account balances and costs for the capital items. I agree with the capital structure and cost 3 of debt contained in WR's March 31, 2018, update. I do not agree with the 9.85% cost of 4 equity.
5 Capital Structure 6 Q. Do you have any adjustments to WR's capital structure?
7 A. Only that I recommend updating the cost and account balances from September 31, 2017, 8 to March 31, 2018. Westar provided this updated information in response to KCC DR 9 # 159. As displayed in the previous two tables, there is a minor change in the capital ratios 10 from the September 31, 2017, balances to the March 31, 2018. It is reasonable to use the
- 11 March 31, 2018, capital structure because the update better reflects the capital costs and 12 ratios that is financing WR's rate base. The rate of return calculation in Staffs ROR will 13 reflect along-term debt ratio of about48.33% and an equity ratio of51.24% (these numbers 14 include some rounding; Staffs Schedule C contains the non-truncated calculations).
15 Q. Is WR's updated capitalization within the range seen in the electric utility industry?
16 A. Yes, financially sound electric utilities have traditionally employed capitalization policies 17 of about 50% debt and 50% equity. The group of electric utilities selected ~s the proxy-18 group for my cost of capital analysis follows this same pattern as seen in the following 19 table.
10
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS
+-- Staff ProJ~ Grou()
1==-~g-TennDebt Ratios Reported by Value-Line Investment Survey ___ _L
--I 18-WSEE-328-RTS I
Allete Inc f ALE I ,
, - + - - - - - - - - - - - + - - - - ! - - !_2_0_1_5-+1- 2016 46.3%1 42.0%
2011 41.0%
i Value-Line Forecasts 201a 40.5%
2019 38.5%
- 21- *23 38.0%
Alliant Energy Corp LNT 48.6%1 52.8% 49.0% 50.0% 50.0% 50.0%
,Ameren Corp AEE 49.3%i 47.7% 49.5%1 49.5% 49.0% 49.5%
iAmericanElectric Power Co. - AEP 49.8%, 50.0% 51.5%! 52.5% 54.5% 50.5%
Consolidated Edison Inc Drure E=gy Coq, New
__ ED
~]DUK l_
- t. 47.9% 50.8%
1 48.6%j ji.6i<]
50.0%!
54.0%1 50.5%
54.5%
49.5%
55.5%
48.0%
57.0'£ ~
Edisonlnternational El Paso Electric Co ------ ---
1IDACORP Inc EIX
!IDA 45.0% 41.8%
IEE-+__-52.7%1___
45.6%, 44.8%
5~ -
45.6%
51.2% -
43.7%
48.0%
53.0~
44.0%:
48.0% I 52.0% r- s.LJ%1-47.5%
42.0% I 44.0% I
-f---- -49.5%! 48.5% ! _- 46.0% I 1
,NorthWestern Corporation --_~NWE 53.1%- 52.0% _ 50.2%,
_)OGE Energy Corp__ __ _ QG_E
- j_ 14.3~;_ 1!:!_~ 41.7~1 __ 4J!!'i__ __ 44.0~_/ _45.Sl!_J 1Pinnacle West Capital Corp JNW ____ 43.0%'. __ 45.6o/{_ 48.9~1 48.0% 48.5% _45.5% .'1
-!Portland General Electric_Co. POR / 47.8%: 48.4o/<<ij 50.1%1 47.0% 50.5% 48.5%
Xcel Energy Inc XEL r- 54.1%! 56.3%1 55.<Jo// 58.0% I 57.0%- 58.0%1
.! - A,ven1gej 48.3~: 1~.5_o/~\ 18_.Z~i -~9.1~~1_ ~-:!_%j 4_~.8%1
~t ~ ---~-: ~- --=-~-=-~-~-~-= -~-
Median! 48.3% 49.2%j 49.8%! 49.5%! 49.3%< 48.3% 1 Minj - - 4io%f 41.1%L 41.0%[-- 40.5% 38.5%1 _ 38.0%
-i- _________________ _Max! ---~-~6.3iy~_55.9%1 __ .58.0%~__Jl0%!- _58.0%_
-i--- _1 ! ;___ . *I , i ___ ---+-
- source: Value-Line Investment Survey (February 16, 2018; March 16, 2018; & April 27, 2018)
- --- - - -* -.- ---- r ; - . . -- .r - - 1- - -[ . - L r 1
2 Q. Is WR's updated capitalization consistent with the capital structure. limitations 3 discussed in the 18-095 S&A?
4 A. Yes, WR's capitalization complies with the provisions of Attachment 1 of the 18-095 S&A.
5 Cost of Debt 6 Q. _Do you propose any adjustments to WR's cost of debt?
7 A. As with the capital structure, I recommend an update from September 31, 2017, to March 8 31, 2018. There are very minor cost differences between these two periods. The updated 9 cost of debt is 4.68%. This current cost of debt compares to a 5.687% cost of debt in WR's 10 last rate case (15-WSEE-115-RTS). The reduction reflects WR's refunding or refinancing 11
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 of debt that has occurred since the test year of December 31, 2014, that was used in that 2 rate case.
J 3 Cost of Equity Analysis 4 .Q. Please summarize Staff's position on Westar's cost of equity?
5 A. Staff recommends that the Commission authorize a 9.30% return on Westar's equity capital 6 (ROE), the same ROE applied for purposes of the Earnings Review & Sharing Plan (ERSP) 7 that was accepted by the Commission in the J 8-095 Docket. My analysis of the current 8 capital markets finds that, inclusive of the benefits from the ERSP and other terms of the 9 18-095 S&A, an ROE of 9.30% is reasonable for Westar and consumers. The benefits that 10 acerue to consumers through the 18-095 S&A are made available with some additional 8
11 risks to the shareholders of Westar. My testimony in the 18-095 Docket discussed the 12 benefits and risks related to 18-095 S&A and I will repeat that discussion because they are 13 equally important to adjudicating the cost ofcapital issues in this Docket.
14 Q. Is Staff recommending an ROE range for the Commission?
15 A. No, at least not in the sense that would be done in a traditional rate case. I recommend the 16 Commission adopt a 9.30% ROE, the same that is used in the ERSP. If for some reason 17 the Commission finds a need to deviate from the 9.30% ROE, then I recommend that a 9
18 range of 9.10% to 9.50%, which is consistent with the terms of the 18-095 S&A. This 19 range is fully supported by my analysis.
8 Testimony of Adam H. Gatewood, 18-KCPE-095-MER filed January 29, 2018; p. 11-15.
9 Non-Unanimous Settlement Agreement; l 8-KCPE-095-MER filed March 17, 2018; at paragraph 32, iv, 1; p. 15.
12
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS.
1 Q. Do you believe the Commission can deviate from the 9.30% ROE even though it 2 adopted the 18-095 S&A?
3 A. Yes, the Commission can deviate from the 9.30% ROE in setting the revenue requirement 4 in.this Docket. If the Commission adopts an ROE lower than 9.30%, Westar has the option 5 of shortening the rate moratorium from five *years to three years. Staff believes there are 6 benefits for consumers to the full five-year rate moratorium that may not be present in a 7 three-year moratmium, such as an incentive to capture merger related synergies and a 8 period of relative rate stability. Those are two examples that are not easily quantified.
9 Q. How broad is th~ support for the 9.30% ROE for Westar?
10 A. The 9.30% ROE set in the 18-095 S&A is supported by Staff (representing the public 11 generally), CURB (representing residential and small business *consumers), Westar (on 12 behalf of shareholders), Sunflower Electric Cooperative, Mid-Kansas Electric Company, 13 The Kansas Power Pool, Midwest Energy, Inc., and Bright Energy, LLC. The signatories 14 to the 18-095 S&A represent diver~e and often opposing interests, especially on ~he issue 15 of an allowed return; seldom do they agree on this issue. In fact, there have been rate cases 16 where practically all issues could be settled among parties except the ROE, thus requiring 17 a hearing and Commission determination just for the allowed return.
18 Q. How does a 9.30% ROE compare to recent decisions from around the country?
19 A. A 9.30% return on equity is at the low-end of recent observations for electric utility r*ate 20 cases. For the first quarter of 2018; the average ROE granted was 9.75% with thirteen 13
Direct Testimony of Adam H. Gatewood DocketNo; 18-WSEE-328-RTS 1 observations. 10 Separating out only those decisions associated with vertically integrated 2 electric utilities and not tied to a limited-issue rider brings the number of observations down 3 to five with an average of 9.78%. 11 Over the past decade, allowed returns have declined 4 nationally, although the rate at which those declines have occurred vary from jurisdiction 5 to jurisdiction. That decline has happened at a more rapid pace in Kansas than in most 6 otherjurisdictions. Over the past several quarters, there appears to *be a plateau in allowed 7 returns; that is the rate of decline has fallen off as shown in the graphs that follow.
8 Q: Please provide sonie background on how Staff arrived at the 9.30% ROE for the 9 ERSP.
10 A. Staff was searching for a productive and fair settlement position for the 18-095 Merger, 11 which led Staff to consider a rate moratorium and.a sharing mechanism of earnings above 12 an allowed return. Thus, it was necessary for Staff to perform a fresh and thorough analysis 13 of capital costs to determine the appropriate threshold for measuring earnings. At that time, 14 we were also aware that both Westar and KCP&L would be filing rate cases in 2018 and 15
- the two utilities expressed a need to have some level of certainty regarding the cost of 16 equity recommendations in their upcoming rate cases, especially if they were going to 17 commit to an extended rate moratorium or an earnings sharing plan. For that reason, parties 18 agreed that the negotiated ROE applied in the ERSP would also become their 10 RRA Regulatory Focus Major Rate Case Decisions: January- March 2018; S&P Global Market Intelligence; April 17, 2018; p. 10.
11 Kentucky Power Co., 9.70% (Kentucky); Public Service Company of Oklahoma, 9.30% (Oklahoma); Interstate Power and Light, Co, 9.98% (Iowa); Duke Energy Progress, LLC, 9.90% (North Carolina); and Consumers Energy Co, 10.00% (Michigan). '
14 r
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 recommendation to use in setting the revenue requirements in the 2018 rate cases.
2 As I discussed in my 18-095 testimony, 12 my cost of capital analysis was developed in a 3 manner and using conventions identicalto those applied in rate cases. The results of my 4 analysis indicated that 9.30% was within a reasonable range for the ERSP. I also found 5 that capital costs were similar to those observed during Westar's and KCPL's last rate cases 6 which occurred in 2015. The Commission set KCPL's ROE at 9.30% and adopted a
- 7. .settlement in which Westar's ROE was about 9.35%. Thus, the cost of capital. analysis 8 provided Staff with the position that KCPL's and Westar's ROE could remain in place 9 from their last rate cases to be used for the ERSP and setting rates in their 2018 rate cases.
10 Q. If the parties to the 18-095 S&A agreed to support a 9.30% ROE in this Docket, why 11 did you perform a new cost of capital study?
12 A. I did this to provide the Commission with. a comparative record on wh~ch to base its 13 decision and to establish facts that demonstrate an ROE of 9.30% is a just and reasonable 14 return in determining Westar's revenue requirement. The signatories to the 18-095 S&A
. \
15 are very much aware that we cannot make a decision for the.Commission. Ultimately, it 16 is the Commission that has to r.eview the evidence and decide if 9.30% is a just and 17 reasonable return for setting Westar's revenue requirement.. The legal standards that I 18 discuss later s~ill apply to the Commission's decision, regardless of the fact that several 19 parties have re;iched an agreement on the issue.
20 Q. How much time has elapsed since the analysis you prepared for the 18-095 docket?
12 Testimony of Adam H. Gatewood, 18-KCPE-095-MER filed January 29, 2018; p. 33.
15
Direct Testimony of Adam H. Gatewood Docket No. i&-WSEE-328-RTS 1 A. The time period of the capital market data I used in the 18-095 analysis was January 1, 2 2017, through December 31, 2017, and Staff filed its testimony on January 29, 2018. The 3 Application in this Docket was filed just days later on February 1, 2018. In this analysis, 4 I relied on financial data gathered from the one year time span of May 201 7 through May 5 2018. Thus, there is a considerable overlap in the time periods when data was gathered.
6 In developing our position in the 18-095 Docket, Staff was cognizant of the timing of the 7 rate filings. Since the timing of these interrelated events were relatively close together, 8 Staff was comfortable with connecting the two while recognizing our responsibility to 9 prove the 9.3% ROE included in the 18-095 Docket is reasonable for both the ERSP and 10 the following rate cases. Had we been looking at a wider time-gap between the 18-095 11 Docket and the rate cases, it likely would have been much more difficult or not possible to 12 have connected the recommendations.
13 Q. What has occurred in the capital markets since the 18-095 analysis?
- 14 A. There are some observable increases in capital costs in the time since the 18-095 analysis.
15 These changes are not dramatic increases to the capital costs observed since Westar's last 16 rate case in 2015 nor outside of the capital costs observed during 2017. In the past six 17 months, the Federal Open Markets Committee (FOMC) of the U.S.1Federal Reserve Board 13 18 has authorized open market operations transactions to increase the Federal Funds Rate in 19 December of2017 and March of 2018. In both cases, the FOMC authorized open market 13 The Federal Funds Rate is the rate at which funds are loaned between Federal Reserve depository institutions on an overnight basis. The Fed Funds Rate is a tool the FOMC uses to carry out its statutory objectives maximum employment, stable prices, and moderating long-term interest rates (12 U.S.C. § 225a). The first _
two statutory objectives are known as the "dual mandate" because of the inherent difficulty in balancing these two objectives.
16
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 operations to increase the effective Federal Funds Rate by 25 basis points to target a Federal 2 Funds Rate of 1.50% to 1.75%. This is an exercise of policy that does not directly change 3 long-term capital costs of public utilities; rather, it is an indication that the policy makers 4 of the FOMC believe that both the U.S. and global economies are sound and growing, thus 5 capable of withstanding minor increases in short-term interest rates. Statements and
\
6 projection material fi:om the March 2018 FOMC meeting indicate continued real GDP 7 growth in the range of 2.0% annually and a desired or targeted inflation rate of 2.0%. A 8 2.0% rate of inflation has been the Fed's target since the Great Recession, although the 9 actual rate of inflation has rarely been as high as this target.
FRED c4 - Effective Feder.,I Fundo Rnlo 3.0 2.5 Iw 1.5 1.0 0.5 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 10 Shaded nrens indic:1/e U.S. ri,cess/ons SOurco: Boord ol Governors !)flho Fode!al Rosorvo Sys1em (US) myl.rod/g/jRllw
.)
11 Longer-term interest rates that are set in the capital markets are also higher than the 12 observations at the end of 2017 when I prepared my 18-095 analysis, though well within 13 the ranges seen since the Great Recession and during early 2017.
17 ,
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS
, FRED~ - l.loody"* Seosoned Boo Corpor:,lo Bond Yield 10 9
8 6
5 4
Jan2008 Jan:2009 Jan2010 Jan2011 Jan2012 Jan2013 Jan2014 Jan2015 Jan2016 Jan2017 Jan2018 Shaded areas indfr:'118 U.S. recessions Source: Moody's myf.red/g/JRQp 1
2 A view of corporate interest rates for the time period associated with Staffs18-095 3 investigation through the investigative period for this Docket indicates a dis!inct trough in 4 corporate bond yields. Clearly, current bond yields have increased from those lows and 5 they are well within the range experienced last year and experienced since the Great 6 Recession. The observations of corporate bond yields are consistent with my cost of capital 7 analyses which show that the cost of equity for electric utilities have not changed since my 8 analysis for the 18-095 investigation.
9 Staff frequently cautions the Commission against relying on cost of capital witness' 10 economic forecasts because the capital markets are widely viewed as efficient, that is, 11 participants factor all available information (including forecasts) into their pricing of 12 securities. Thus, the market prices embody the forecasts and expectations of investors. For 13 that reason, adding a regulatory body's "forecast" is not necessary and could be 18
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 counterproductive (it ~ould be wrong or contrary to investors' expectations). That being 2 said, from Staffs perspective in negotiating the 18-095 S&A, we were aware that allowed 3 returns set by commission and interest rates exhibited a plateau from a multi-year decline.
4 And, given the length of the economic expansion, we were likely at a juncture where there 5 is more upside potential with capital costs than a continuation of.the decline that we have 6 witnessed over the past ten years.
- FRED ,,d - Moody"* Seasoned Baa Corpor:ilo Bond Vlold 4.9 4.8 4.7 4.6 4.5 4A 4.3 4.2 \
4.1 2017-01 2017-03 2017-05 2017-07 2017-09 2017-11 2018-01 2018-03 2018-05 7 Shaded mew in<i~cars U.S. recessions *Source: Moody's mylred/g/jSPV 8 Q. Please discuss the additional risks posed by the 18-095 S&A that was approved by the 9 Commission on May 24, 2018.
10 A. The added. risks to shareholders include: 1) a five year rate moratorium during which 11 Wesfar cannot file a rate case in Kansas; 2) the minimum annual credits to consumers; 3) 12 $225 million of merger savings built into the revenue requirement in this rate case; and 4) 13 the presence of a sharing mechanism for excess earnings above the 9.30% allowed return.
19
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 Staff believes the 18-095 S&A presents additional risks to shareholders because it: 1) 2 demands annual credits to consumers that has the effect of lowering Westar' s earned return; 3 2) reduces the value of earnings if Westar earns above its allowed return; 3) sets a period 4 of five years during which Westar cannot file a rate case if its earnings are less than its 5 allowed return; and 4) sets a period of five years during which Westar cannot file a rate 6 case if its capital costs increase. With the 18-095 S&A in place that sets a period of five 7 years during which Westar cannot file a rate case, Westar must find cost savings equal to 8 the guaranteed fixed annual credits in order to achieve its authorized return. Consumers 9 could also see additional annual credits if the Applicants profits exceed the 9.30%
10 threshold. Westar' s shareholders will only benefit by retaining a portion of any earnings 11 above the allowed return over the rate moratorium.
12 Q. Without the 18-095 S&A, would Staff be inclined to recommend a 9.30% ROE for 13 Westar?
14 A. Without the 18-095 S&A, Staff would likely be recommending a lower allowed return for 15 Westar given the current financial markets. As I discussed earlier, and in my 18-095 16 testimony, there are risks and benefits to the 18-095 S&A, primarily the ERSP. Five year 17 rate moratorium and bill credits to consumers cause me to distinguish this Docket from a 18 traditional rate case. Without those risks and benefits, Staffs recommendation - based 19
- purely on the results of my financial analysis - would likely be closer to 9 .00%. However, 20 Staffs recommendation would also have to consider the fact that a 9.00% recommendation 21 is a full 30 basis points below the lowest authorized ROE observation in the current national 22 average and would, thus, be a highly contentious recommendation, which would most 20
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 likely result in litigation. I would also note that I have been applying a gradual approach 2 to my ROE recommendations over the last several years. So,. it is likely my 3 recommendation would be between 9.10% and 9.20% given the plateau of allowed returns 4 over the last several quarters and the fact that a 9.00% return is 30 basis points below the 5 lowest observation in the recent national average. 14
/
6 Q. Please summarize the results of your cost of equity analysis.
7 A. The following table summarizes the cost of equity estimates from my study in this Docket; 8 the details of each financial model appears later in my testimony. I relied on a discounted 9 cash flow (DCF) model,* a variation of the DCF model known as an internal rate of return*
10 (IRR) analysis, and the capital asset pricing model (CAPM). These are the models I 11 typically use to estimate a utility's required return on equity. The results in this table are 12 based on the capital markets using data from May of 2017 through April of 2018.
- 1 .,
14 RRA Regulatory Focus Major Rate Case Decisions: January - March 2018; S&P Global Market Intelligence; April 17, 2018; p. 10.
21
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS t---s~;.--;;ry of Starrs Cost of Equi~ Est~ates ___ L -----r-
' l-- ~ -- - ~ -__18-WSEE-328-RTS I ::::r=~~
Discounted Cash Flow Analyses
-~-t I
---r---- --- - - .-------------------------~rrl- Low-rHighi.
I1wO:S1age G.-owth DCF Model:- - ----- --. ~ 8.22% I 7.19o/a-8.64J .
---r-*--- ~ l
+- .__ +
Based on the Average of Short-Term Growth ____ __[__
_forecasts & Long:'ferm nGDP Forecasts__ ____ _ -~ _____ r------
------- --,----~-- _, ---- }-
- 8.02%: 7.20%! 9.08%!
,Internal Rate ofReturn-Multi-Stage DCF Analysis:
}Using Short-Term Grow~EPS _q_~owth & ----
JLong-Term nGDP Forecast
~=---r------+ --~:--r -~-~- j I , i i-1------ -- -- --- --- -- .----- --------------- _L_ _______l_____ _ L ________ j__
-;- _____________ ~apital Asset Pricing M~de,Is - ~ - ____ --t I
-i---
i I
.---~----r :
zr-I
_11Based on Historical Return DataLgathered from ___ _! _9.00%l __ 7.83%~_10.93~j-
_1926 - 2017; Reported -.---
by SBBI; Duff & Phelps ! I i
r----------+------ , - - ------;--
1
! ; ! i I I~;s-;;d~!1 F~~~~~rn Data Publi-shedby- -~: -- _I__ 6.09%r_i~~r~L-I:! i~[
- 1.~._
I Morgan Asset Management (2018 edition) '
- i 1
2 Q. For a point of comparison, please summarize return on equity decisions by this 3 Commission and Commissions across the country?
4 A. The first table contains allowed return on equity decisions made by this Commission in 5 litigated rate cases. As a point of reference to the prevailing capital markets at that time, I 6 included the yield on the Baa rated corporate bonds as of the month of the Commission's 7 decision.
22
Direct Testimony of Adam H. Gatewood Docket No. l 8-WSEE-328-RTS I
-,-----------------------'---------~----~- I I I ---~-- I ______ l ______ !
I
~--*---- __________ Commission Detennined Allowed RO Es -- Kansas Utilities I
I I
- - ! --* -* ,_____ -~-R~~~ted: -Orde;~d B~aB~nd
+- ,-- ----. --i*---*--* -----,-- ---,---~-
' Company , Docket '1 Order Date I ROE ROE : Yield. I
-~Kans}lsgty)'ower&Light_ !!5-KCPE-116-RTS _j 9/10/~ _ _!Q.30%l_ 9.301'.'~--- 4.8W11_L
,AtmosEnergyCorp. 14-ATMG-320-RTS 1 9/4/20141 10.53% 9.10%1 4.89%1 1Kansas CityPower&Light [12-KCPE-764-RTS ' 12/13/2012! 10.40%i 9.50%i 4.80%!
__ :Kansas City Power & Ligh! :; ! O-KCPE-415-RTS _ !!~2!2010 L 10.75% I 10.00% i ~,~§1"11_[
- Wesrar§nergy~---*---'05-WSEE-981-RTS 12/28/20051 ll.50%i 10:0o~ 6.10%1
- efestarEnergylnc. _______ 101-WSRE-436-RTS _, 7/25/20011 12.75%1 *-*** 11.02%1 ___ 7.97%1
- Kansas Gas Service Co. . 193,305-U 4/15/1996: 12.00%1 10.50%; 7.77%1 _
'.sourc~s~ SNIJRRA; Federal Reserve B~ ofSt. Loui-s, FRED *-
1 2 The following chart is broader in both the time period and reporting scope. It indicates the 3 median return on equity granted in fully litigated rate cases across the nation from 1980 4 through March of 2018. As a point of reference to the prevailing capital markets, I included 5 the average yield to maturity of Baa corporate bonds.
Long-Term View of Electric Utility ROE and Baa Corporate Bond Yields 17.00%
16.50%
16.00%
15.50%
15.00%
14.501%
___:!ii~-- -.
- --- *- . -A"A-*** -- .
14.00% --*- &-----
13.50% - - --*
13.00%
12.50%
12.00%
11.50%
11.00%
10.50% 0 0
~-~"1.r;_*~..~~~"~***!~""!T1.ii.~
- -*-*- ... ~. ...
10.00% *.*.*** .*..
9.50%,
9.00%
8.50%
8.00%,
7.50% -- -** - ---
7.00%
6 ..50~~
- --- -- ---~--;._-_-_ --- --------------
**~.-..
6.00% -*- -- -- - *- ----* ----- ---- -----*-------------
5.50% ----------- --- -- ------- -*-------- ---------*------------- --
5.00%
4.50% -- - - -- -- -- --------- ------------*.- . --------- - - - - - - - - - - - - - -
- 4.00%
3.50% * - - - - - - - - - - - - - - - - - - - - - - - - - -
A Median ROE eBaa Coiporate Yield 6
7 The next chart highlights a shorter time peri.od, the last four years from early 2014 through 23
Direct Testimony of A.dam H. Gatewood Docket No. 18-WSEE-328-RTS 1 March of 2018. Compared to the decline seen in the chart of the long-term changes, the 2 past four years show a plateau in the median allowed return granted.
Electric Utility ROE and Baa Corporate Bond Yields 11.00%" --- -- - ----------------- - ------------------------- ------- ----- ---------- --
10.50% - - -- - ----------- ----- - ---- --- - --.&-- - - - - - ------ - ---- --- ---
10.00%
9.50% Ji.--*-- ~-----~- ~--"' ---...----*-- ...- -- ..._____ ... __ ---.&- ... ____ ... __
9.00%
8.50%
8.00%
7.50%
i.00%
6.50%
6.00% - __ . - --- -- - :.
5.50% --
- ~*~ *-*-* *-~-
5.00%
4.50%
4.00%
eBaa Corporate Yield .A.Median ROE 3
4 Q. How does Staff's recommendation compare to the returns available on other 5 investments?
6 A. The following table shows that Staffs recommendation of a 9.30% return on equity allows 7 investors a risk premium over less risky debt investments. These types of income -
8 producing securities are viewed as alternatives to investments in utility stocks because, like 9 utility stocks, bonds offer stable valuations and higher current income, relative to the equity 10 market. Risk premiums vary over time and across market conditions; thus, there is not a 11 benchmark risk premium or formula that sets a reasonable return on equity at a given 12 interest rate. The Commission has not set a definitive spread over bond yields, but the 13 Commission's Order in 15-KCPE-115-RTS {15-116) noted that its decision allowed 24
Direct Testimony of Adam H. Gatewood Docket No. l 8-WSEE-'328-RTS 1 KCP&L a risk premium of 525 basis points .over the yield on its long-term debt. 15 At that 2 time,just as now, KCP&L and Westar have almost identical bond ratings, thus, they should 3 be viewed as comparable in risk. In that Docket, Staff argued that a 525 basis point risk 4 premium over the bond yield was reasonable as it offered stockholders a higher return than
.. 5 available on the lower risk debt securities. The Commission agreed and applied Staffs 6 risk premium to arrive at an allowed return for KCP&L. I believe the 9.30% ROE is 7 consistent with the Commission's rationale in the 15-116 Order because it allows for a risk 8 premium in excess of 540 basis p'oints over the yields on Westar's long-term bonds.
. )
15 Order issued on KCP&L's Application on Rate Change; 15-KCPE-116-RTS; September 10, 2015; para. 34.
25
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS
_L____ :_________J________ : I - - - - - - L __________ J_
' KCC Staffs Risk Premium Over Fixed Income Yields
_____ __ __ _____ ____ Based on a 9.30% Return on Eguit~ _______ _
--1--- __ _____ _ Fixed Income Yield Observations May 2017 throug~ApJ:il 2018 ________ .-
! 18-WSEE-328-RTS --+
- _ _ _ _ _ _ _]_ ---,- --------- ~ ------------~----- I __ I _
_:_____ 30 Year (1) Utility Bonds (2) Moody's (3) : Westar (4)
Treasury Bond-;- - A/A Baa/BBB Corporate Baa--:- Bonds YTM
_Ap_r-:_U! 3.Q8%j 4.17%; 4.50%: ~?1%~ '!,Q6_~J_
Mar r _3_,Q9~l 4.12%-, 4.4~%J 4:6~%: 4.03%'
Feb-18 3.13% 4.14% 4.42% 4.47% 3.94%i -
Jan-18 2.88% 3.8Jo/o. 4.14% 4.25%, 3.71%*
Dec-17 2.77% 3.80% __'+/-*~-- 4.22%; 3.70%.
- ___ Nov-17 __ *_ _2.81%! _________ 3.84% _4.1_!%*_ -_-4.06~*-~---- -=l,72%~
-* __ Oct-I] __ ,.. ~ - _______ l,92%,_ 4.21,Y<>_._ _ _ _ 4.32%;__ _ __ 3.79%
_" Sep::17 _ ___ 1,J8%, 3.89% +/-19% _ _ 4.30% ---------~.76%,
____ Aug-17 -- ~:80~_ _l~?~ 4.20% 0
_'!}~o/o: ________ }.79%:.
-- --- Jul::.!7 __ . __ _b~_. _____ 3.99%,. 4.31% --- '!_.40~t- 3.82%*
Jun-17 2.80%, 3.94%
4.28% 4.38%,
+-
3.85%'
May-17 ' 2.96% 4.12% 4.48% 4.56%* 4.04%
___*Average 2_2Q~~- 3.97%, +/-_28_o/o__ _ __ 4.39% 3.85%'
Risk Premiums Over Fixed Income Securities KCC Staff's Recommended ROE 9.30%
Average Yield on 30 Year Treasury_!3o_nd,_*_ _2_.9_0_o/c_o_ ___,
Equity Risk Premium Ove_r the 30-Year T!."asury Bond Yield 6.40%
KCC Staff's Recommended ROE 9.30%
__ Average Yield on "A" Rated Utility)3_on__d_s_____3_._97_o/c_*_----,
Equity Risk Premium_Over "A" Utility~nd Yield. 5.33%
KCC Staff's Recommended ROE 9.30%
A\'erage Yield ~n "BBB/B_!l~' _Rated Utility Bonds ___4_.2_8_o/c_o- ~
Equity Risk Premium Over "Baa/BBB". Utility Bond Yield_ 5.02%
KCC Staff's Recommended ROE 9.30%
Average Yield on "BBB/Baa" Rated Utility Bonds 4.39%
Equity Risk r.;;mium bve-rMoody's Baa/BBB Corporate Bond Yiei"it---4-.9-t-o/c-.--
KCC
- - , __Recommended Staff's - - -- -- *-
ROE 9.30%
Average Yield on Westar Bonds ___3_.8_5_o/c_o_ _
Premium over Yield on Westar Bonds 5.45%
___ I) Board of Governors of the Federal Reserve System(US), 30-Year Treasury Constant Maturity (Federal Reserve Bank of St. Louis;Release H:15) _
_ 2) Yield on A and BBB/Baa Rated Public Utilty Bon~ 25 to 30 Maturity
--+- Rep~rted weekly in Value-Line Investment Survey2 Selection & Opjnion Section ___ _ ______ _
- 3) Yi~ld on M~ody's Baa Corpora~e_ Bonds re!l_ort~d at FRED _(Federal Reserv~ Ban~ of St. Lcmjs Electronic Data)
_ 4) ~age yre~to maturrtyrepooetLbyJ'INRAon WR4.10%, 2043; WR4.625%, 2043;and WR4.125%,_2042, _____ ---~
1 2 Standards for a Just & Reasonable Rate of Return 3 Q. What is the role of rate of return in setting a revenue requirement for public utilities?
26
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 A. The standards for setting a just and reasonable rate of return require that, to be reasonable, 2 the allowed return must reflect the risks associated with an equity investment in the utility.
3 For the allowed return to be in that reasonable range, it must compensate for those added 4 risks while capturing a fair proportion of benefits for consumers. The terms of the 18-095 5 S&A, although beneficial to all stake-holders, possess several risks to shareholders not seen 6 in a traditional rate case and the Commission must consider these risks.
7 The allowed ROE is best described as the forward-looking discount rate that is necessary 8 to induce equity investors to commit their capital to the enterprise. Standards used to gauge 9 the fairness and reasonableness of an allowed ROE have been stated by courts, as the result 10 of appeals of decisions issued by regulatory agencies. Financial analysts and policy-11 makers rely on the courts' decisions as a guide in estimating the appropriate cost of capital.
12 The opinions do not articulate precisely how to estimate or model a reasonable cost of
. 13 capital. Instead, the decisions provide critical questions for policy makers and analysts to 14 consider in determining a reasonable return for a regulated utility.
15 In general, United States Supreme Court decisions state that returns granted to regulated 16 public utilities should: 1) be commensurate with returns on investments of similar. risk; 2) 17 be sufficient to assure the financial integrity of the utility under efficient economic 18 management; and 3) change over time with changes in the money market and business 19 conditions. 16 An important take-away from these decisions is that the Supreme Court of 20 the United States has* afforded regulatory agencies a significant amount of latitude in 16 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).
27
Direct Testimony of Adam H. Gatewood Docket No. l 8-WSEE-328-RTS 1 establishing an appropriate ROR and ROE for a utility. The Kansas Supreme Court has 2 recognized and follows this body oflaw. 17 This Commission has noted this fact in Orders 3 issued in previous dockets. 18 4 Q. Discuss how financial analysts apply the standards established by the Court.
5 A. For an allowed ROE to meet the legal standards, the return should be as specific as possible 6 to the utility in question. There are several court cases that, as a group, are viewed as the 7 keystone to measuring the adequacy of a utility's allowed return. The earliest of these 8* decisions go back to an era when it was not only the "rate of return" at issue but also the 9 fundamental measurement of the investment in the utility enterprise, commonly referred to 10 as rate base. This is less of an issue today as regulators, utility management, and investors 11 readily accept actual historic-depreciated value as the measure of investment to estimate 12 the value of a utility's rate.base (as opposed to reproduction cost or market value). The 13 Court's decision in Bluefield addressed both rate base and ROR. 19 Treatises on rate of 14 return for public utilities, such as The Cost of Capital - A Practitioner's Guide, agree that 15 Bluefield lays out the four standards for a fair return.
16 1) Comparable Earnings - a utility is entitled to a return similar to that being earned by 17 other enterprises with similar risks, but not as high as those earned by highly profitable 18 or speculative ventures; 19 2) Financial Integrity- a utility is entitled to a return level reasonably sufficient to assure 20 financial soundness; 21 3) Capital Attraction - a utility is entitled to a return sufficient to support its credit and 22 raise capital; and 17 Kansas Gas & Elec. Co. v. State Corp. Comm'n, 239 Kan. 483,491, 720 P. 2d 1063, 1072 (1986).
18 Order: I) Addressing Prudence; 2) Approving Application, in Part; & 3) Ruling on Pending Requests, Docket No.
10-KCPE-415-RTS; November 22, 2010; 37-38.
19 Bluefield Water Works & Improvement Co. v. Pub. Svc. Comm 'n of West Virginia, 262 U.S. 679, 692-3 (1923).
28
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS
\_
1 4) Changing Level of Returns - a fair return can change along with economic conditions 2 and capital markets. 20 3 As a financial analyst formulating rate of return analyses for our state commission, I take 4 from Bluefield that the Court requires a rate order that allows a utility an opportunity to 5 earn a return consistent with the utility's risk profile and consistent with observations in 6 the capital markets. The Court's decision in Hope, 21 like that in Bluefield, dealt with both 7 valuation of rate base, as well as rate of return on that rate base. With respect to the rate of
\*
8 return, the Court in Hope affirmed the four standards set out in Bluefield.
9 KCC Proxy Group 10 Q. How did you select a proxy group for your cost of equity analysis?
11 A. Using the following parameters, identical to those that I used in the 18-095 Docket, I was 12 able to select a group of fourteen electric utilities that are comparable to Westar. To narrow 13 the universe of potential proxy companies, I used the following selection criteria:
14
- Has publicly traded common stock 15
- Is an electric utility followed by Value-Line Investment Survey 16
- No recent spin-offs, mergers or distressed assets 20 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. .
21 Federal Power Comm 'n v. Hope Natural Gas Co., 320 U.S. 591,603 (1944). "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 corresponding 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 arrived at. For we are of the view that the end result in this case cannot be condemned under the Act as unjust and unreasonable from the investor or company viewpoint."
29
Direct Testimony ofAdam H. Gatewood DocketNo. 18-WSEE-328-RTS 1
- Exhibits stable dividends-No recent dividend cuts 2
- Possesses an investment grade bond rating between A3/A- and Baa2/BBB 3
- Earns at' least 70% of its annual revenues by providing regulated electric utility
- 4 services 5 Stock-price data is critical to a cost of equity analysis as.that price data encapsulates the 6 market participants' valuation of the company. Selecting companies that investment 7 research companies like Value-Line categorize as electric utilities focuses the analysis on 8 companies facing similar types of business" risks and opportunities and insures that 9 publically available financial data is available. As a starting point, this parameter is 10 important as it assures us the companies generally derive their earnings in electric utility 11 industry. The following table contains all of the electric utilities followed by Value-Line.
12 The bold and .boxed cells indicate the primary reason for rejection from the proxy group.
30
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS
. l -*- -- .1 -- _J I Proxy Company Selection 08-WSEE-328-RTS)_.
2 3 I _4_ ! 5 ' 6 7 .1 8 9 *:i_ 10 0 *FERCSelectionCriteria*** _____________ _ 111 KCC Staff Screens 111
. : -------- 1. No , Dividends 2017 Value-Line: Electric Utiliti~s *uBond Ratingu* Ann~u~~~- -l~o-fiiio;tfl - ~o17 1
- Electric-(?~r;~i.;~s-- ;
Company Name 1 Mo~dy*.-1
- S&P *r Merger Reductions History 1 %R~; - ] o/~;e-~-;., I j
__ Allete Inc;_ . _
J.._Alliant Energy Corl} --- -- - -
,Ameren Corp
---+-~_-_E_ -
'.ALE IA3
- oo :a~ -
4~
.BBB+
i A- - -
1 BBB+ Yes Yes y;;
X x
_ _ _x______-+_ _
Jx t- 74.9%1
_:x_ . ___ ], ____ 85.6%
s2~o/~~
86.0% __ . 85.0%1 _
'American Electric Power Company Inc ~EP ,B¥1_ I~- . Yes x x I "- : 86,7% 9_+/-.)~i
.~,;;;,~IGR-mln;:*_* - - - * * .A_G_!l_. jB~I_ ~!3B+ _ Yes x x " ~LO%j 85._7o/o'
-~- AVA _ *Hydro-One~rger* I '
lllaehHillsCaFf!_______ _ BKH i', 1 *Sellingoil&gasassets* , __ j ___ x --~!_____ !____
Cem:erPeiRtERergylne _ CNP _+!3aal _ _ A- Yes 1.__________ x ____ _ x_ ___ __ 31.7% 45.4%
,O!S lleergi Carp CMS ~ - _,BBB+ ~-*-* -----"--------* _ x L x 67.5% 60.3%
,<;o~o!ida~~-!;4iso!JlnC - ~~D - 1 A3 A- !Yes , x x x 76.6%] 73.3%:
Elemieiaelleergi D I ** , * ! *A~<1uiring!>CAN~* I ---r
-~-lleergi c~"'I'~ DTE IBaal 'BBB+ Ive~ x x x 40.5%! 62.7%!
1
-'~* E!','rgy Co!p _l'le~ DUK !~aa_l 'A- IY~i x x J_< 9.Q2'!1~ 86.6%
Edisonlnternational EIX iA3 iaa+ rYes 1 ~ , x ~ 99.0%1 89.9%
_-EI-Pas~El~~tricCo__ - ~ - IBaal - *eeB* !Ye;* ; ' X X - IOCJ.0%i -* *--*.
~Hlef!ll C~rp_ *ETR IBaa2 - -- ~BBB+-- Yes -iClo~i~g 4 non-reg nuclear plants: \
_ ~-"**~ee ~He_fgj ES ,B.;,.l !A+ !SPLT - - - !' . - - ' x x 71.5% 53.0%
_Ene~aft Carp EXC [13,;;,i 'BBB iYe; - x X X 44.4%
1
~i!sllle~rgi_Ce~p 0 FE Baa3 'BBB- ~O. _; Sub. B~nk_!111>tcy/elim. !!*~*reg X 69.4% 64.2%
Fer!i5;-IH& FTS.TO(B_"!'_3 'A- X X 54.0%
0Great P}ei~_ lleef!ll lee G?(P ,Baa2. .BBB+ Yes Westar I Ila eiian llleei.ie lfld"5tfies lne IDACORP Inc HE IDA J
- Baal
!BBB-
- BBB 1~0 X X X 88~0%] 47.0%
IYes X X 99.0%1* 99.0%
MGE llee~ lee MGEE !Al 'AA- !NO X X X 73.5% 56.2%;
V"-~
1
- }!e,illlra lleergi lee NEE \B"!'~ 'A- X X X 69.0%! 51.4%!
NorthWestern Cmporation NWE iBaal ~i!_~ ,Yes X X X 79.3%: 80.1%
OGE Energy Corp ;Q.GE ~ ;AJ A- Iv~*** X X X 100.0%1 QMer '.J:;;;;-c;;;;-. 19_TTR [e.;i - 1!!1_!1!_ jf.,_~- ' X X X 51.0%! 84.3%:
-~~~- PCG la.;;! _BBB+_ :Yes X __j__
Pinnacle West Capital Corp PNW ~ - ,A* [Tos-- 98.0%
P}lH ~esaHFees IHe * *- PNM !Baa3 !BBB+ lSPLIT- X X
-Portland General Electric Company J'()_R \A3 ,BBB r*-*--
.Yes X X X - IQ0.0%J P!'bCerper_a!i~H PPL jB~ 'A- :ves Forex risk X X 71.9%: 59.2%
Pttelie Ser i_ee llH!erpriae C~etljl lfle PEG :Baal BBB+ :Yes X X X 66.9%
. SC ~l' _CeFf!eratieH SCG ! ! Construction issues/AC 1
Se"1jlrelleergi SRE iBaal ,BBB+ Yes Onocor ac uisition X X 35.7%
- sa...~.. c~e so :Baa:i A- 'Yes Construction issues X X 65.8%
He_etren Cef13 VVC A- iYes X X X 29.1%
WEC Energy Group WEC A3 A- Yes X X X n_:estar eH0Iffi IRe WR '.Baal ,BBB+ 'Yes Great Plains l~0.0%;
Xcel Energy Inc XEL ,A3 A- Yes X X X 84.9%,
. } ) ~utilities followed by Value-Line Investment Survey(U.S. ccmipanies) Credit ~ating Range
- 2) Ticker symbol ' Moody's ' - S&P
- 3) Moc,_dy~~!*Eit rati~g_(L]Jl) d_ata from ~&P Global_ Mar_ket Intelligence A3 A-
- 4) _S&P credit rating (LTR) data from S&P Global Market Intelligence Baal BBB+ \Y~tar.
0
- 5) Within credit rating range of both rating agencies Baa2 BBB
- 6) No*;,;.~ge~~ ;cq~~ti~I\ o~-s~I;;-.;r;;scts (Value-Li~e & S&P Global Market Jntellig~nce)
- 7) _No fon:casted _div\~e_nd !e_ductio~ (Va_iue-Line) _ ' _ *
- x = no reduction
- 8) No dividend reduction in 2017 (Value-line & S&P Global Market Intelligence) .x= no forecasted reduction
- 9) R~venues from;egclated electrjcope;ations--% of total revenues(S&P Global Market JntelligenceL _ 70% of Revenues from electric utiJity ~ndustry 10)_ A~_se_ts efreguLated eleEtric opera!io";' (li&P G/obal Mar_~*\ Intelligence),
1 2 Credit ratings shown in columns three and four are the first screen applied to the population.
3 The current ratings for Westar is Baal by Moody's and BBB+ by S&P; these ratings are 4 firmly in the mid-ran$e of the investment-grade ratings. The selection criteria uses a range 31
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 22 1 that is one notch either side ofWestar's ratings which is a range of A3/A- to .Baa2/BBB.
2 In column six, I listed any merger or acquisitions in process or any significant financial 3 issues that make it difficult to assess the utility's long-term earnings prospects. In this 4 criteria, I found there are several utilities involved in acquisitions. SCANA and Southern 5 Co. are excluded due to their construction problems with nuclear power plants; SCANA 6 has also ~igned in acquisition plan with Dominion. I excluded utilities involved in 7 acquisitions and those with significant construction issues because both types of events 8 cause uncertainty around future earnings. I also excluded PPL Corp. due to its investments 9 overseas. PPL reports that 30% of its revenues are subject to foreign exchange risk. This 10 is an atypical situation in the U.S. electric utility industry and a risk that is distinct from 11 Westar. The filter in column six focuses the study on electric utilities with known 12 prospective earnings power.
13 Columns seven and eight are similar to column five in that these criteria would eliminate 14 firms that have or are forecasted to reduce annual dividends. In the public utility sectors 15 where management and boards strive for a record of stable dividend growth, a dividend Credit Rating Table
~i~Y~_: ~~
Aaa . AM
~_!__-.- AAT Aa2. I M Aa3 M-AI A+
A2 : _A_
__ A3 ___ ' __ A- -
Baal_ , BIIB+
Baa2 ; BBB Baa3 I BBB-
!!*I I BB+
_ Ba2 __ ( BB__
_ Ba3 , BB- __
Bl ' B+
B2 : ~
BJ B-Caal CCC+
c_~ CCC Caa3 _C::_g:.::_
Ca cc c+
C 22 C D 32
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 reduction signals maJor change in ongoing operations and is probably a sign that 2 managements cannot expect stable eammgs growth in the foreseeable years. Such 3 candidates should not be in the proxy group for W_estar because that situation 1s not 4 consistent with Westar's prospects. Pacific Gas & Electric is the only utility eliminated 5 with this criteria; it suspended its dividend payments in December of 201 7.
6 The criteria in columns mne and ten attempt to ascertain whether providing regulated 7 electric utilities services is the primary business of the company. I set the threshold for 8 revenl!es from electric utility service at 70% of total revenues. This is a subjective cutoff, 9 but it works for this analysis because meeting that threshold means that the company is 10 largely focused on, and earnings are ~erived from, providing regulated electric utility 11 services. The following table contains Staffs proxy group of 14 electric utilities for the 12 cost of equity and capital structure analyses.
2 j 4 __?-_ J 6 7 8 9 10
- uFERC Selection Criteria*.. . __ _ _ ___ * *Kee Staff Screens*
No ' Dividends 2017 Value-Line: Electric Utilities _ _ ... Bond Rating*~* _. Anno~!;d !"IE Planned . ..1!!!.? __ Electric o.,.rations Company Name :_ Moody's S&P ; Merger Reductions History -~/,,R~v I %~sets*
Allele Inc . ALE 'A3 'BBB+ Yes x .. __ . l': x 74.9%1 Alliant Energy Corp LNT 'Baal A- .. ,Ye; x x x . -85.6%[. 82.6%
AmerenCorp AEE ,Baal BBB+ Yes x x x 86.0%; 85.0%
~ricanElectricPowerComp,;,,ylnc AEP ,Baal A- Yes x x x_ 86.7%/ 94.1%
Consolidated Edison Inc .ED ;A3 A- Yes x x x 76.6% 73.3%
__ DukeEnergyj%~w DUK :Baal A- Yes "- x x 90.5%! 86.6%
Edison International EIX :A:i- -** BBB+ Yes x x x 99.0%*-- 89.9%
~ _El Paso.Electri~ Co_
- ________ EE -#al _ BBB ' , Yes x x x , 100:oo/t,I
- IDACORP Inc ,g:i~ j~a~l
- BBB * *To-~ * * ~ - - . ** ~--:-~ _ T * - 29~ - 92:Q~--
-' N~rthWe~te.:;;*c~rporntion -
OGEEnergyCorp NWE IBaal OGE ,A3
- BBB -
A-
- ~Y~s
'Yes !
_I X x
- - ' -- X - - - - - - X x x
--+-- ~'-~
- 100.0%
_ Pi~.;-le West Capjta)Corp __ ___ PNW _~A3
- _A- __-__ *y~s __ J ___ x ____ , __ ;, __ ~ - - - ~ - - - - ~ _ 98.0%
, ,~o~'!Ild General Electric Company 'POR 1A3 BBB Yes : x x x 1 100.0%
,Xcel Energy Inc 'XEL 1A3 A~-- ;Yes i x
- x * ' x* i 84.9% -
- I 1 1
-- -l)E:le~trt-.c-utiliiks .fullow~d *i;;,*Val_ue__-L-ine_In_v-es-tm,~-n-t -Surv--ey- *c-u-.s-.c-o*mp
--am-, es-)- ----- Credit Rating R~nge
- 2) Ticke~-symb;,j* * * ** - ' **
- 1 * * ' * --
- 1 i __
M;,ody's l S&P
- 3) Moody's credii rating (LTR) d~ta fto11!_S&J' Q!o_bal Market brtel)ig~~-ce * :
- A3 A-
- 4) S&P credit rating (LTR) data fromS&P Global Market Intelligence Baal BB~+ !Westar
- s) Within-~e~t;~tingr~e ofbofu;~ti~pg_enci;;*- -- - --- Baa2 - -BBB 1
- 6) No merger, acquistion, or sale of assets (Value-Line & S&P Global Market Intelligence)
- 7) No forE~asi~_d dividend reducpon (V;lu1o-Llne) j _ -_ - i : _ II
!!) No divi_dend red,u:tion in 20 lI_(Yalue-Line & S&P Global _Market Jntellig~~~) _i_ ________ ~:_ ___ _
- 9) Revenues from regulated electric operations 70% of total revenues (S&P Global Market Intelligence) I _i 13
- 10) Ass~~ ;,fregufated. ~le~tric o p ~ ~ b a l Markei*hrt~ilig~~ __ l_ __ - .. - .. :. ------~----
1 I . , 1 . +----- **+-* --- -
33
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 Return on Equity Analysis 2 Q. How did you perform the cost of equity analysis?
3 A. I am using discounted cash flow models and capital asset pricing models; essentially the 4 same form of analysis used in all recent rate cases and the 18-095 Docket to establish the 5 9.3 0% threshold for the ERSP.
6 Q. Does the DCF model meet the legal standards discussed earlier in your testimony?
7 A. Yes, a cost of equity estimate derived from the DCF model meets the legal standards 8 discussed above if the model incorporates current information from the capital markets via 9 current stock prices and accurate .data that investors use to establish their discount rate.
10 This market-based information ensures the cost of equity estimates evaluate investors' 11 required rate of return or discount rate that reflects the current economic environment.
12 The DCF model is a valuation model used by investors to value different types of 13 investments such as real estate, bonds, and equity securities. The DCF model is a useful 14 tool to value any investment that involves regular, periodic cash flows. The notion of 15 discounting a future .
receipt of cash back
. /
to the present so as to place a price or value on an 16 investment goes back centuries. 23 The premise of the DCF model in the valuation of 17 common stock is that investors determine the value of a company's common stock by 18' discounting its future dividend payments back to the present. The cornerstone of the DCF 19 model is the process of discounting those future cash flows back to the present at the 23 The formal presentation of the DCF model as we use it today dates back to the 1930's in Irving Fisher's book: The Theory of Interest and John Burr Williams' 1938 text: The Theory of Investment Value. These two authors expressed the DCF model in modem economic terms.
34
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 investors' required return. An investor's. required rate of return is risk-sensitive and 2 sensitive to the returns available on investments of comparable risk throughout the global 3 capital markets. In other words, as the risk of the investment increases, so will the 4 investors' required return. A higher required rate of return decreases the present value of 5 the stream of dividends that equates to the price of the stock. So, all other variables being 6 equal, investors price the riskier of two common stocks lower because the cash flows or 7 dividends are discounted back to the present at a higher rate.
8 The form of the DCF model that regulatory agencies are accustomed to seeing is often 9 referred to as the Gordon Growth Model, which is a model that values the security at the 10 present value of a stream of cash flows (dividends) growing at a constant rate into 11 perpetuity. The basic form of this DCF equation is:
D0 (1 + g) 12 Po= -(-Ke---g-)
13 where:
14 Po= the value of the common stock or asset 15 Do= the current dividend of the stock or annual cash flow from the asset 16 g = the annual growth rate of the dividend or cash flow forever 17 Ke = cost of equity or required rate ofretum for the stockholders 18 Or 19 Stock Price= Annual Dividend/ (Req'd Rate of Return-Dividend Growth Rate) 20 This is the form of the equation commonly found in texts regarding finance, investments, 21 and asset valuation. Such texts are inclusive of both theory and practical application.
35
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 Regulatory agencies responsible for setting rates and revenue requirements want to know 2 the investors' required rate ofretum or Ke in the equation. So, we solve the equation for 3 that variable. The equation below shows the algebraic isolation of the investors' required 4 rate of return. By isolating investors' required rate of return .in the equation, we can 5 estimate it by knowing the stock's dividend yield and the annual dividend growth rate 6 expected by investors. That form of the equation is:
D0 (1 + g) 7 Ke= Po +g This equation is frequently written out as:
9 Req'd Rate.of Return= (Dividend/Current Stock Price)+ Dividend Growth Rate 10 or 11 Req'd Rate of Return= Dividend Yield+ Dividend Growth Rate 12 13 Or as commonly abbreviated by regulatory agencies 14 Ke=y+ g 15 Where: y = Dividend Yield 16 g = Expected Dividend Growth 17 Through a handful of inputs, the DCF model distills down to an equation, a complex 18 cognitive process performed by investors to arrive at a discount rate and valuation of the 19 security. As ~ith any equation that attempts to model behavior, there. are a host of 20 assumptions that come along with it. Those assumptions are:
36
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1
- Ke corresponds only to the specific stream of future dividends, _rather than earnings, 2 and that constitutes the source of value.
3 *
- The discount rate (Ke) must exceed the growth rate (g).
4
- The constant growth rate will continue for an indefinite future.
5
- Investors require the same discount rate (Ke) each year.
6
- There is no external financing.
7 Q. Why is it reasonable to accept these assumptions?.
8 A. The DCF model is attempting to emulate investors' behavior; distilling human _behavior 9 into a handful of inputs demands simplifying assumptions. The question becomes whether 10 the assumptions are so contrary to investors' behavior in the real-world that the model 11 output becomes meaningless or illogical. I do not believe the assumptions of the DCF 12 model are contrary to investor behavior. Moreover, there are methods I use to evaluate 13 whether an output falls outside of the realm of reality. For example; the output can be 14 compared with the returns available on other investments such as long-term corporate 15 bonds. There were no observations eliminated using thi~ screen. 24 J
16 Discounted Cash Flow Model 17 Q. How did you_calculate the dividend yield (y) component of the DCF model?
18 A. The dividend yield (y) is the easier of the two components to measure as it is easily 19 observable in 'daily stock price reports. It is calculated by dividing the stock's annual 20 dividend payment per share by its market price per share.
24 Staff appiies this screen using the interest rates of Baa Utility Bonds and the yields on utility specific debt shown in the Risk Premium Table. Staff adds l 00 basis points to these yields as a minimum risk premium test. Cost of equity observations below this level are eliminated from the average. FERC proceedings apply a similar test for outliers.
37
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-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 subscription services such as Value-Line. The DCF model requires a forward-looking 4 dividend payment which is often the current year's dividend payment increased by the 5 forecasted growth rate for next year. In lieu of forecasting, I obtained the 2019 forecasted 6 dividend per share information from Value-Line Investment Sµrvey. The Value-Line 7 reports for each of the proxy companies are attached as Schedule AHG-3. I obtained the 8 stock prices for the dividend yields from YahooFinance. For this analysis, I used weekly 9 stock prfoe observations taken from May 8, 2017, through May 7, 2018. The stock prices 10 for each of the proxy companies appears on Schedule AHG-4. My DCF analysis 11 incorporates a dividend yield based on expected 2019 dividend payments.
38
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS
~
+-_____ ___ _____
- j
___ _____L___
____L I Di\'.!dendY~tJr'lfii!Jftl!Y7,~_!~
J__
Staff Proxy Grou!l_______ _ _____L=f t~ - - -_-- =r:=ki~ ~:--~,~,J ~ -~~4~t
_jAIIete Inc _____ .. _ ALE I $ _23!_ $ 66.64 ! $ 81.24 $ 73.94 _!_74.2! I
-1AlliantEnergyCorp _
1
- LNT * $ 1.42 $ 36.84 I$ 45.55 $ 41.19 $41.581 2.8~~ ___ '.!:_5_1~
3.12% 3.85%
IArnerenCorp_ _ _ _ _ _ _ ~AEE _i $ 1.93 $ 51.89' I $ .§_4.89 $ 58.39 $57.85 2.97% 3.72% -
_1~i:i~nE~~_i_cPower<:;o,_ .J~P l ~ ~.63 ! §lRJ.~ Z~-Q7_. ~_ _?0.70 E0.81 __ 1 3)1~ __ ~.15~--
_ConsolidatedEdisonlnc ___ '.ED__, ___ ~_2.96 i $ 73.73 L!_89.70 I$ 81.72 $81.80 I__ _D~---~
1
_Jl?~e !='.~gy<;:o_rp_l'-l~w 1J?l)I(_ J $ ~-§_Q_J t_7.2.93 [ ~ ~1.8_!) I~ }Dl I H~.l~_j 4.14_o/o~ 1-~~-
JEdison International I
_ _ _ IEIX __ ~ $ 2.57 $ 57.63 I $ !:u! I $ 70.50 ) $ 72.46 I _ 3.08%_l 4.46%
jEI Paso Electric Co ~ t
- $ 1.52 1 $ 48.05 i $ 6lfil! 54.60 $ 53.72 !
- 2.49%/ _ ~~ _
_ l!?A(2(?RP_ I!]~_ _ _ I_QA_ '. $ ~,~§-iTJ_ 79.~9 \ $ 100.0~ \ ~ ~_9_&! $ §_8.59_ I 2.?6_'Yo1 3.22%
iNorthWesternCorporation ___ _:__~-~~-2.30 $ 50.01 [J_ §4.47 [ $ 57.24 $57.97 ! __ 3.5~%1 ___!~>-
1
- OGEEnergyCorp :ooE - - ~ - ~ $ 29.59 I$ 37.32 I$ 33.46 $34.18 4.13~--~ _
1
_ Pinnacle West C::~pital C::~!ll_ !'.._'N_~ _:J, _3.Q? ~ $_ 7-~~-i ~- ~~~8_1 $ 8_3.!i -~-84.62 : 3,2Z'Yo! _ 4.09% _
- '1 ~~9~__
1 JPortland General Electric Co. _RQ_g__ J ~-_U_(J_-1-~--39._02 J !_?0.11 ! _ ~ $44.71 I___ __3_,~4%>-
lxcel Energy Inc *:XEL ! $ 1.60 $ 41.511 $ 52.22 [ $ 46.86 1 $47.16 I 3.oWoJ 3.85%
1
- _ _
- j __: ; I j ~~!!g~J 2.49o/o[ 5.2_!'.Yo~
______ l _____ __;_ _____ l_ ________ ---1--------1* : ----~
I-
_L
- 1) Dividends per Share for 2019 Forecasted by Value-Line Investment Survey ____; ___ . _ !---
-~)_ Minimum 12 month price observed from May 8, 2017, through May 7,_2018 ! , ,
- 3) Maximuml2monthpriceobservedfromMay8,2017,throughMay7,2018 ; _ : __ ,.... ____ J __
-~i Mid-point is the av~rage of minimum price and maximump!ice-- ---,- - -~-~ l- - : ' l.
~ Mean price for the time period of May 8, 2017, through M~y 7, 2018 (weekly observationsl __ _ __ ___ _
_;&) Minimumdividendyieldavailableft~time!leriod __ _ _ _ ---;--- __ _ _____:_
- ,7) Maximum
*dividend
- ---** yield
--- available
-,*- --- from *-r time- period 1
2 Forecasted Growth Rates for the DCF Model 3 Q. Please discuss the importance of the second component, the growth rate (g), in the 4 DCF equation.
5 A. The "g" represents the anticipated annual growth rate in cash-flows that investors expect 6 to receive througl). dividends from the stock. This is a challenging and contentious issue in 7 a DCF analysis for two reasons. First, it is a key element in the DCF model or any form 8 of a discounted cash flow arialysis because the growth rate has a one-for-one effect on the 9 required return produced by the model. All other factors being equal, a higher growth rate 10 results in an equally higher return on equity for the utility. Second, there is an element of 39
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS l subjectivity to the growth rate, due to the uncertainty about future earnings and dividends.
2 Q. How did you estimate the growth rate in the DCF model?
3 A. The appropriate growth estimate is that which is expected by the market and factored into 4 investors' analyses to estimate stock prices. That is, it is the growth estimate investors 5 used to determine the stock price. Earnings per share growth forecasts are commonly 6 incorporated into the DCF model. Investment firms that publish growth forecasts typically 7 publish three to five-year annual growth estimates for earnings. Value-Line Investment 8 Survey also provides dividend growth rate forecasts; it is the only firm that I am aware of 9 that does so. Three to five years is as far into the future as analysts forecast for a specific 10 company.
11 Q. How do investors estimate the dividend growth rate beyond the three to five-year 12 horizon of the short-term growth forecasts?
13 A. For a long-term perspective of potential growth, investors rely on forecasts of the broad 14 --, economy as measured by annual ch_anges forecasted for the nation's gross domestic product_
15 (GDP). There are sources for long-term growt;h estimates of this country's GDP that extend 16 out more than 20 years. Academic texts and investment professionals use these forecasts 17 in DCF models as a forecast of potential long-term growth of corporate dividend payments.
18 GDP refers to the market value of all final goods and services produced within a country 19 in a given period. Nominal GDP (nGDP) is that measure of goods and services which 20 includes effects of price changes - better known as inflation. Inflation must be included 21 for our forecast because the DCF analysis is interested in the nominal required return. That 40
- Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 is to say, investors' expectations of inflation are contained in their required return. Keep 2 in mind that the "headline" GDP reported in the media is real GDP, which is GDP less the 3 inflation experienced over the measurement period.
4 Q. Is it accepted practice in securities valuation to use nGDP growth estimates in the 5 DCFmodel?
6 A. Yes, in the federal regulatory arena, similar to the responsibilities of the KCC, the Federal 7 Energy Regulatory Commission (FERC) uses nGDP to estimate the cost of equity. FERC 8 has reviewed the issue of long.,.term growth estimates used in DCF models. It took 9 comments from stakeholders that included state commissions, customers, investment 10 bankers, and interstate pipeline companies. 25 Testimony from these parties made it clear 11 that long-term estimates of nGDP are a common component of valuation analyses 12 conducted by investment professionals. From that proceeding, FERC concluded that long-
\
13 term growth estimates of nGDP should be the estimate of long-term growth in the DCF 14 models used to estimate required returns for interstate pipeline companies because that is 15 consistent with investor behavior. 26 In June of 2014, FERC concluded that the same 16 methodology should be used in setting the required returns for electric transmission 17 companies. 27 Although the Commission has never explicitly endorsed long-run GDP 18 growth as an input, it is clear that the growth estimate used by Staff in the 15-116 Docket 19 were considered credible by the Commission. 28 In that analysis; I relied on the same 25 Transcript from Technical Conference held on January 23, 2008: FERC Docket PL07-2-000.
26 Policy Statement, FERC Docket PL07-2-000 (April i7, 2008); FERC Opinion No. 486, FERC Docket RP04-274 (Oct. 19, 2006). .
27 Opinion No. 531; June 19, 2014; 147 FERC 61,234; para 36.
28 Order issued September 10, 2015; Docket 15-KCPE-116-RTS; para. 34; p. 15-16.
41
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 sources for long-term nGDP growth as I am using in this analysis.
2 Q. Is there academic support for this issue?
3 A. Yes, academic research has shown that nGDP growth :forecasts are an important input to 4 valuation studies because the analyst has to consider whether a company's annual earnings 5 can grow as fast as, o! even faster than, the broad economy. In two of his books devoted 6 to the subject of asset valuation, Dr. Aswath Damodaran discusses the nature of a stable 7 growth rate for DCF models. 29 He argues for viewing nominal economic growth as the 8 absolute maximum when using a stable-growth model, such as the DCF model we are 9 usmg.
10 "The stable growth rate *cannot exceed the growth rate of the economy in 11 which a firm operates, but it can be lower: There is nothing that prevents 12 us from assuming that mature firms will become a smaller part of the 13 .economy and it may, in fact, be the JrJOre reasonable assumption to make.
14 Note that the growth rate of an economy reflects the contributions of both 15 young, higher growth firms and mature, stable growth firms. If the former 16 grow at a rate much higher than the growth rate of the economy, the latter 17 have to grow at a rate that is lower. " (Damodaran on Valuation: Security 18 Analysis for Investment and Corporate Finance, 2nd edition; Aswath 19 Damodaran; p. 148) 20 "The growth rate of a company cannot be greater than that of the economy 21 but it can be less. Firms can become smaller over time relative to the 22 economy. Thus, even though the cap on the growth rate may be the nominal 23 growth rate ofthe economy, analysts may use growth rates much lower than 24 this value for individual companies. " (Damodaran on Valuation: Security 25 Analysis for Investment and Corporate Finance, 2nd edition; Aswath 26 Damodaran; p.159) 29 Investment Valuation: Tools and Techniques for Determining the Value of Any Asset, 2nd Edition and Damodaran on Valuation: Security Analysis for Investment and Corporate Finance, 2nd Edition.
42
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 It is worth noting that Professor Damodaran cites the nGDP growth p~ojection as a ceiling 2 for long-term growth in most valuation studies. Certainly, there are industries that will 3 exceed the average for a period of time, but even for those industries, rapid growth cannot 4 continue forever.
5 Q. Does the view that nGDP growth is a ceiling on long-term earnings growth exist 6 outside of academia?
7 A. Yes, valuation analysts carefully consider the long-run growth rates used to value assets 8
- very carefully because using an incorrect growth estimate will lead to incorrectly valuing 9 an asset. The authors of the previous discussion, Peter L. Bernstein and Robert D. Amott, 10 have both published in peer-reviewed academic journals and books on investment strategy, 11 as well as building careers in the field of asset management and investment strategy.
12 Furthermore, institutions directly involved in asset valuation and asset management that 13 apply valuation models to analyze potential acquisition and merger transactions recognize 14
- that estimates of firm-specific growth are a driver to the value of an asset; overstating 15 growth would cause a model to overestimate the value of the asset which would result in 16 an economic loss to the investor. These experts also warn of a ceiling to earnings growth 17 rates as being no more than that of broad economic growth.
18 "Growth rate;* Few companies can be expected to grow faster than the 19 economy for long periods. The best estimate is probably the expected long-20
- term rate of consumption growth for the industry's products, plus inflation. " .
21 (Valuation: Measuring and Managing the Value of Companies; Tim Koller, 22 Mark Goedhart, and David Wessels; McKinsey & Co; 4th ed; p. 275.)
43
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS .
1 The following quote from J.P. Morgan Asset Management (JPMAM) addresses the macro 2 or economy-wide measures of profits, and it is consistent with the firm-specific view 3 expressed by asset valuation experts in that analysts must be aware of the fore casted growth 4 rates applied in valuation models and how those growth forecasts comport with broad 5 measures of forecasted economic growth.
6 "One common mistake is to assume that earnings and dividends received 7 by investors can grow in line with-or even in excess of-overall economic 8 growth (GDP) in perpetuity. Granted, it is almost a truism that aggregate 9 earnings must grow at the same pace as the overaU economy in the very 10 long run; otherwise, profits would eventually outstrip the size of the entire I
11 economy or dwindle to an insignificant share of it. But not all of this 12 earnings growth accrues to existing shareholders. On the contrary, a large 13 portion of economic growth comes from the birth of new enterprises. Some 14 commentators suggest (for example, Bernstein and Arnott, 2003; Cornell, 15 2010) that new enterprises account for more than half of GDP growth in 16 the US., while in some rapidly developing economies new enterprises may 17 account for the lion's share of overall economic growth. " 30 18 Goldman Sachs Asset Management explains 'to its clients, "Our *analysis reveals that the 19 link between GDP growth and equity returns is, in fact, very strong." 31 The asset pricing 20 formula of a dividend discount model shows how GDP growth influences the return they 21 earn on equity assets: " ... the dividend growth rate will equate to the growth rate in 22 earnings. Assuming that earnings gro~h is equal to, or jus.t associated with GDP growth, 23 a direct link with equity returns is established." 32 Goldman Sachs also states that research 24 has demonstrated that GDP growth is a proxy for earnings growth.
30 Long-term Capital Market Return Assumptions: 2015 Estimates and Thinking Behind the Numbers; J.P. Morgan Asset Management; p. 25; https://am.jpmorgan.com/us/institutional/ltcmra 31 "Linking GDP Growth and Equity Returns"; Monthly Insights: From the Office of the Chairman; Goldman Sachs Asset Management; May 2011; p. 1.
32 "Linking GDP Growth and Equity Returns"; Monthly Insights: From the Office of the Chairman; Goldman Sachs Asset Management; May 2011; p. 2.
44
/
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 Q. Do you believe this evidence justifies incorporating long-run nGDP growth forecasts 2 into cost of equity analyses of utility companies?
~ A. Yes, because we have to ascertain the discount rate investors apply to the future cash flows 4 from an investment in these utilities. Therefore, the Commission should emulate investors' 5 analytical practices as closely as possible to determine investors' discount rate. As noted 6 above, investment professionals include a long-run growth forecast for the general 7 economy (in addition to company-specific short-run growth estimc1:tes) when applying the 8 DCF and capital asset pricing model, and that measure of macro-economic growth serves 9 as the :upper bounds of a firm-specific analysis. Therefore, the Commission should 10 consider the same information when estimating a utility's required return.
11 Q. How did you estimate long-ru~ nominal GDP growth?
12 A. .I averaged the long-run nGDP forecasts of the Energy Information Agency (EIA) and the 13 Social Security Administration (SSA). The average of these two forecasts composes the 14 long-run growth estimate in the DCF analysis. The nGDP growth forecasts published by 15 EIA and SSA-OADSI are the same sources that I relied on over the past decade.
45
Direct Testimony of Adam H. Gatewood Docket No. I 8-WSEE-328-RTS
__ (_ ---------- - . ------------- _l _____ J_
-I _ No~a!_ (;!)! E!ti_!ll_at~s , I_
I
__ jEnex:gy Information ~gency (EIA) 2015 _-_ 2-~~--~ ~L~ ! I
-fj Social Security Administration (SSA)
OADSI Trustees Re~rt 2017 : 2095 t'
L 4.41 % I J ~~ ===~ ... -~~~=~. Av, .~I Additional GDP Estimates
-~;;;M~2017_ Outlook for Energy 2015 - 2040---r _-- --- - -r I
!2.2% Real GDP+ 2.2 GDP Deflator from SSA : 4.40%1
-; -- -~ --__--- - _-_ ------ -- -~ -- - __-- -- - - ) - ---___ J_
'. Congresssional Budget Office Nominal GDP Forecast ! :
-?0_!2: 2020 ---- ___ -- _ __ ---- _ -- -- _ _ :- _3.50~_
_ *J021_-2027 -- --- -- -------- --- ------ - - ' 3.90%,
[ ____________ ------ ---- --------- ------- - --- - - i_~ -;J---*--
-- !Federal
-- Reserve Open Market Committee Long-run Forecast
r----
~ 2.2% Real GDP + 2.0 PCE Inflation ____ ___ __ ___ _4.20o/~_
1 2 Q. Are these two the only two sources for long-run GDP forecasts?
3 A. There are other source shown in the table and they are wholly consistent with the EIA and 4 SSA forecasts.
5 DCF Results 6 A. Please discuss the results of your DCF analysis.
7 Q. The results of my DCF analysis appear in the following table. The results seen in this DCF 8 analysis are very much the same as the DCF results in my 18-095 analysis. As I have set 9 out the foundations for the DCF analysis in the previous pages, in this section, I will discuss 10 the specific information that I relied oh for the DCF model and interpret the results.
46
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS t I ____ _J _J _____ l _________ j__ ___ ~
+------ -----~-~J).;;~~.t~t~~~~~ An,I~ . c~. **~ . ~ * * * * - f i=-_-_____-1-:-={ 1 2 --~3 --T_-4*+--5=f 1- --- - -- --- - f -j---- -JtJE~T~- - - G~-- ~~!~~~~ l Alletelnc AlliantEnergy§p _________ ,LNT
_ AmerenCorp
!ALE r-_i
____ _iAEE ___ ~ __ -1:._97%__
2.88%
3.12%
3.51%
3.85%
3.72%
4.89% 7.77%1 5.18% :*: 8.30%[
5.22% 8.20%1 8.40%
9.03%
8.94%
American Electric Power Co. --- \AEP __ _I ____ 3.37% 4.15% 4.73%i 8.10%1 8.89%
Consolidated Edison Inc _ _ ED _____ [ _ ___ 3.30% _ 4:01 % ___ }.8lo/_!l_] _-- 7.}~-- -7.83%-
J?llke _E_nergy_ Corp New !DlJ!< , 4.~4o/o_ 5.21% 4:~1_%1 8.45%1 9.5]%
1 1Edisonlnternational IEIX 3.08o/~f 4.46% 4.60% 7.68%1 9.06%
T,:;"jEl Paso Electric Co -- : _- - -~-: -~ _-_- - - - ~ 3.16%1_-- 4.88% :_T36%L __ 8.04~ _
_ IDACORP Inc __ IDA L. _ _ - ~ - _3~ _ __4.30% _____6.86%; __ 7.52%
-!NorthWestern Corp_._______ _ _ ,NWE 1
--t* _ 3.57%1 4.60% 3.92%\ __ _2_49%1 __ 8.52o/~
oGEEnergyCorp____________ joog_ ________ ~l3%_ 5.20% __ 4.71% 1 _ -~~~..'!.J-----~
4
~ Pinnacle W~JtalCorp __ _ (TI'!W _ ~ _ ___ ~ ___ 4.09% __ _ __ 4.48% I _ 7. 75% \ _ J~.llil
,PoJ"tlans!G~ner~lElectricCo. :poR ~.99o/o_, 3.~'!%1! '!-_11% 7.10%l 7.~5%j 1Xcel Energy Inc IXEL i 3.06%! 3.85% 4.98% 8.04%1 8.83%1
~- _________ ________ _______ j_ _____ :_ ---------~ __ faerageofeachcoltnnnl _7.79%! __ 8.64o/~
_Jr _ _ ___ __ _ __ ___ __ _ I L _ ______ 1_ Average ofall observations I_ _-~--------f 1 __ __ ________ 1 _ _ _ I________ j___Rangeofallobservatio;;i ~:~§.o/~ 1- _?:?lCYo_l 1 _________________________ . _; _ _ _ _ _ _ _ _ _ j _______ I______ ________ 1
_ ! 1) 2018 annual dividend divided by maximum price observed (5/8/2017 through 5/7/2017) _
' 2) 2018 annual dividend divided by minimum price observed (5/8/2017 through 5/7/2018) 43)ForecastedEPSgro~h _______
1
-~ _______
- 4) Low-end estimate = col 1 + col 3 _ _ _ ._ , ,
, - - - - - - - - - - - - - - - * -- *1 - - - ,. - - l-- - -- -- -
-~1_Hi~:!)_destimate=__c:__ol_]:::_~~~~- _1 _ ___ +----- _ -t- _____ - l.
1 ' ! I I I 2 Pricing data was gathered from YahooFinance for each of the proxy companies fro~ the
\
3 time period of May 8, 2017, through May 7, 2018, on a weekly basis. The low dividend 4 yield is computed using the projected 2019 dividend divided by the average of the weekly 5 high prices while the high dividend yield is computed using the average weekly low prices.
6 Q. How did you arrive at a growth rate for each proxy company?
47
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 A. The growth rate is the average of the short-term growth rates 33 and the long-run forecast 2 of nGDP of 4.30%. The following table summarizes all of the observed growth forecasts, 3 both historical and forecasted.
4 Q. How is the long-run nGDP forecast applied in your DCF analysis?
5 A. The long-run nGDP growth forecast of 4.30% is averaged with the short-run growth 6 forecasts. In my DCF analysis, I give equal weight to short-run and long-run growth 7 forecasts. The weighting is certainly debatable because we cannot know precisely how 8 investors weight the two forecast horizons: At FERC, in both natural gas pipeline and 9 electric transmission rate cases, the short-run growth is afforded a two-thirds weighting 10 and the nGDP forecast a one-third weighting. Whatever the weighting an analyst applies 11 between the short-term and long-term .growth forecasts, the analysis needs to be 12 constructed in a manner that distinguishes between the growth potential of each time 13 horizon.
33 For each proxy company, I gathered three short-run, three to five-year growth forecasts for earnings and dividend from Value-Line Investment Survey; as well as analysts' earnings growth projections by Thomson Financial Network (1/B/E/S) reported by YahooFinance .. I/B/E/S aggregates analysts' earnings forecasts and reports the mean of those estimates. FactSet is a service similar to I/B/E/S in that it aggregates analysts' forecasts and publishes the mean and median of estimates. FactSet data was obtained through S&P Global Market Intelligence.
48.
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS
- _L_ - J _'._ ___ __l__ -- - l -- _;_ . _ -* L ___ L_ _____ L __ _
+- ---- ----- ------- - -- .
t- Staff Proxy Group~- ______ . __ _ _________ _
Growth Rate Summai-), ___ _______ _________________ +
18-WSEE-328-RTS 1
i ' I
- j
-,~- -
I
------------ -- -i-- I t-2 , 3 , 4 Value-Line_~_!<!_ri1:_Data ___ ____
10 Year 1 5 Year 1_ _ 5_~* 6 Value Line
, 7 j 8 1 9 Forec~~dG_!'!_Wf_t~~t~~-r=-- _________
,_ _1_0 __
- Thomson FactSet I Short-run Long-term t'J_- ______ ji_
11 DCF
, EPS '!DPS I EPS I DPS EPS : DPS I EPS EPS I Avera e nGDP Growth Rate
- \Ile~ Jnc. __ ~AJ-1
- = \ l.5_Q_'1'ol _3.50~J ~2Q'Yi_ LO.OJ~ 4_.5_0_'l:~ 4:50% ~0%1 6.~o/oj_ 5.48% 4.30% -
'.~!ian1En1orgy_~rp" _QI_T _( 5._Q!J% __?_.59_~ §2Q~ _ 6.50% __ 6.50'lij_ -~OQ_~ 2,_8_Q_~ ~-~3% 6.06% 4.30%
[Ameren Corp. _ _ _ _ _ _ AEE ~_:-~-4.00% 0.50%, 2.00% - 7.50%! 4.50%' _ 6.30% _§.28% 6.15% 4.30%
- Ameri~
- "°E~ctri_<cP_o_werCo.. ~P : 3"QO% _4.00~t 5.50%' 4.50% 4.50%* 5.00%! 5.79%1 1.3.?_% __ 5.17% 4.30%
1
~Cons~d.ated Ed!s~'!..!nc: go_ :_ 1,50% U!!'lh 2:so%T 2.00% 3_-QQ.~'4- 3.50%1 3.40~ 3_.38~"-l - . _}.32~ - ... 4.30')'.
- DukeEnergy~rp~ _____ ,DUK _1 _ 3.50% _ 0.00%1 0.50% _ 2.50% ___ 4.50%' __ 4.50%,_ 4.25%
- _4.06%, 4.33% __ 4.30% ______ _
- Edison Jnternatioml EIX I 2.50% 6.00%' 2.50% 9.00% 4.50% 8.00%1 2.62% 4.47%\ 4.90% 4.30%. ..+/-:§_~_
,E_!_!:'~so El~ctric Co,
- IDACORP Jnc.
-* i_;:_g _~f ~~0% _ o"o~ _ o:~Oo/.'!. !!.Q.!l.1(, -- .1,?_0'y.,
IDA 1 7.50%_ 5.50%J_ 4.~0_%: 10.50% 3.50~1 6.50Jo\ 3.10%
7,0o%j_ ~,~OJ,, _5)_0~ 5.45~ ~ 4.3_0o/o[ -- 4_-~~
4.12%1 4_,1~ 4.30~~; 4.30%:
'NortbWestemCo!P.:___ __ - - - ~ L _ _8_._Q_Q% -~__50%: _7.00% 7.00% ___3.50%. __4.50%1 _ 3.16% _ 3.01%! 3.54% _4_.30%! __ _ 3.92%1
,OGEEnergyCorp~---- QQF: I 4.5Q~l 1-~0_o/~: l_._Q~ 8.50% ~-?Q.'Y~ ! ~ ~~_Q_~l 4_~~~- -~!!.r- _ 4,:J_Q~j 4.71Jo~
_Pil111ll_cl1o West Capital Corp. PNW 1 4.00% 2.50%, 5.00% 2.50% 5.00%, 5.50% 1 3.63%1 4.54~; 4.67% 4.30%1 4.48%1 1
6.00%, 2.65%: _ 3.02%: 3.92% _4.30%1----. 4.11%1 0
PortlandGenera!ElectricCo.JOR __ _!00%1 _')_.~_:J_.50% _3.50% _ 4.00%
~ . ; ; - ~ - - - - ,XEL ! . 5.50%! 4.50%: 5.00% 5.50% 5.50% 5.50%: 5.89%, 5.73%: 5.66% 4.30% 4.98%T l Mi!'J. -!.00% -4.0QJf Q,~--- 2~QQ~ _ ~_()_~:. -~50o/"t- ~.§.2~ 3.0!~ 3.:J_~ _ 30-8.!'Yo~
____ _ __ _ __ __ __ Maxi 8.00% _ 9.00%1 7.00%' _18.00% 7.50%:_ 8.00%* ___ 6.30% 6.90%[ _ 6.15% ________ -+ _ __ 1,22% _
1 Mean: 4.14% 3.64% 3.54% 6.07% 4.54% 1 5.64%: 4.54%, 4.72%j 4.86% i 4.58%*
-~- . t * - .. _- -- '. - . -- - l . . . . - ... : . .. :r
_.!)
- Historic I 0-ywearnLngp~e annuaLgi-~wth rate repyrted by Value-Line , I
--- -- ---+- -
- 2) Historic I0-year d1vdend per share annual gi-owth rate reported by Value-Line :
- 3) Historic 5-y~;;;. e~ng.s J>er sha~e ~ gro~furat~ report~d by V;hie-Line- : ..;
_ __ _ _ __ . _ 4rHistoric 5-year dividend per share annual growth rate !!>J>Orted by Value-Line [ _ _ ________ _ ,______ _
-~ 3 to 5-year forecasted annual earnin~J>er share growth rate by Value-Line ~ __ _ ---,-----* ______ _
6)'3 to 5-year forecasted annual dividends_J>er share gi-5>wth rate by Value-Line I ' _.1_ __ _ _ _. __
- 7) 5-year forecasted annual earnings per share growth rate. Consensus forecasts gatherd by Thomson-Reuters
- and rejlorted-~t Yah~oFimnce on May 3, 201_s__j_ _____ ~ __ *::__~-~-~~ ___ I_ ~ ___ -;- ~~ __'..::_ __ _
- 8) Long-term forecasted annual earnings J>er share gi-owth rate. Consensus forecasts gathered by FactSet and reported j
_at S&P Glo~al ~~et ~lligence_ (fka: _SNL Financial) O!) May 3, 2_018
_ _2)_~~~ of3 to 5-year forecasted annnal growth rates ______ -*-- _
I 0) Long-te~ fo.r~casted n~mi_nal 9DP growth_rate i
- 11) Average of short-term and long-term growth rates l - -* 1 - - - - .- -I 1
2 Q. What are your *observations of the short-run growth forecasts?
3 A. The average of the short-run growth forecasts for the proxy group is 4.86% with a range of 4 3.32% to 6.15%.
5 Internal Rate of Return (IRR) Analysis 6 Q. Please discuss the internal rate of return (IRR) analysis that you performed.
7 A. An IRR analysis of an investment is a form of a discounted cash flow analysis, only with 8 a more complex equation than the Gordon Growth Model that we applied in the previous 49
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 section. In the IRR analysis, we are able to apply the five-year growth forecasts to only 2 the intended next five years of dividends, with the remaining years growing at the long-run
)
3 nGDP forecasted growth rate. In the age of spreadsheets, the IRR equation is not that much 4 harder to manage than the basic dividend yield plus growth DCF model (a.k.a. Gordon 5 Growth Model) and, as the IRR model allows us to apply the growth forecasts to their 6 respective forecast periods, the IM model provides important information to policy 7 makers because it recognizes the respective time spans of both the short~run (three to five-8 year earnings growth) and long-run (nGDP growth rate) forecasts.~ The full output of the 9 IRR calculations appears in Schedule AHG-5; the following table summarizes the results.
10 In the IRR model, short-term growth forecasts are given much less weight than in the two-11 stage DCF analysis; five years of a several hundred year time horizon or five percent as 12 opposed to a weighting of 50 percent that I applied in the two-stage DCF model. As a 13 result of the greater weighting of the long-term growth estimate, the average for the proxy 14 . group in the IRR analysis is 16 basis points lower than the two-stage DCF results.
50
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS
~
-t--- _
Sta~Proxy Group--: *.
Internal Rate of Return (IRR) Results _
18-WSEE-328-RTS
-1 __
IAiletelnc ~ 7.68%1 IAlliant EnergySo/p ___ --- __ ___ - J.()Oo/~ _
1Ameren Corp I 7.98%
~American Electric Power Company m~[ 8.25% 1. ___
ConsolidatedEdisonlnc Duke Energy Corp New
_ + 7.94%1
- - -- -- ---- i --9.08% I -
-f- ---------------
Edison International ---*- -- - - ------ --,------ I 8.03% ---
El Paso -Electric Co I 7.25%
IDACORP Inc I
--- ----- -------1-- 7.20% I 1
NorthWestern Coryoration _ _ _ ___ j___ 8.30%1--
1 0GE Energy Corp _______ ----~--8.89%1--
1 IPinnacle West Capital Corp Portland General Electric Co~an:t__ __
__ \Xcel Energy Inc l--
- 8.00~~
7 .67% _
7.95% 1_
I 8.02% -
I - - - - - - - - - - - - - - - - - - - - - ____Meanl _
I Min 7.20%
I,- --- ---- - ------* -~-- - --
Ii '
-- _ Ma1-- _9.08%r _
1 I i I 2 In this instance, as is usually the cas~ with public utilities, there is not a wide difference 3 between the short-term growth rates and long-term nGDP growth, therefore the difference 4 in weighting of the two growth rates between the DCF and IRR analyses do not cause a 5 large difference in results.
6 Capital Asset Pricing Model (CAPM) Analysis 7 Q. Please describe the capital asset pricing,model (CAPM).
8 A. The CAPM offers an explanation of the positive relationship between risk and ROR 9 required by investors. 34 It is appealing to regulators because it meets the legal standards I 34 The theoretical support for the CAPM is the work done by Harry Markowitz ("Portfolio Selection," Journal of
.Finance, March, J 952). W.F. Sharpe added the concept of a risk-free rate of return to the Markowitz model ("A Simplified Model of Portfolio Analysis," Management Science, Janua~, 1963).
51
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS
/
1 discussed above, as it can be .structured to incorporate current data from the financial 2 markets and the unique risks of the utility in question.
3 Ke = Rf+ Beta (Rm - Rf) or 4 Ke= Rf+ Beta (Rp) 5 Where:
6 Ke = required return on equity 7 Rf= .return on a risk-free security 8 Rm = an expected return from the market as a whole 9 Rp = risk premium available to investors through purchasing common stocks 10 instead of risk-free securities often calculated as Rm - Rf 11 Beta= volatility of the security's or portfolio's return relative to the volatility of 12 the market's return with the market beta equal to 1. 0 13 Rf 14 The Rf estimate is the interest rate investors believe represents a riskless return. Although 15 it is a simple concept, the answer is not universally agreed upon. It is widely accepted that 16 a debt instrument issued by the U.S. Government is a risk-free instrument. An investment 17 in U.S. Treasury Bonds is a risk-free investment if the investor plans to hold it until 18 maturity. The risk-free instrument chosen will have an effect on the results of the CAPM 19 analysis. Whichever instrument is selected,.it should be used consistently in the equation.
20 Beta 21 The beta coefficient measures the volatility of the return earned by the utility's stock 22 relative to the volatility of the returns earned by the broader equity market. The broad 52
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 equity market is frequently measured using the S&P 500 Index. This measure provides a 2 look at the risk and volatility of a stock relative to other investments. A stock with a beta 3 of 1 is equally as volatile as the market as a whole. A stock .
with a beta of 0.5 is half as 4 volatile as the market. Value-Line reports that Westar has a beta coefficient of0.70. These 5 are similar to the average for the proxy group of 0.67.
6 Rm 7 Rm is the expected return on the stock market as measured by a broad market index such 8 as the S&P 500~ This represents the total return consisting of the price change of the index 9 plus dividends earned for the year.
10 Rp 11 The risk premium is the difference between investors' expected return from the stock 12 market and their expected return from the risk-free investment over the same time period.
13 The risk premium is written as Rm-Rf. The market *return and the risk-free return should 14 be taken from the same time period so as to accurately measure the additional return a
15 required by investors to take on the risk of common stocks over the risk-free investment.
16 Q. Please discuss your CAPM analysis.
17 A. I took two distinct* approaches to the CAPM analysis. I performed one analysis using 18 purely historic measures ofreturns from the stock and bond markets and a second analysis 19 using forecasted returns. The results using historic returns are drastically higher, 9.38%,
20 when compared to results using forecasted returns of 6.93%.
53
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 Both forms ofmy CAPM analysis incorporate the high and low beta coefficients observed 2 in the proxy group. This beta indicates that the volatility of the proxy group is about 65%
3 of that exhibited by the broad market and, accordingly, investors would expect a relatively 4 lower return from stocks of public utilities than the broad market. This is a clear indication 5 that public utility companies like Applicants and the proxy group are less volatile (and less 6 risky) than the broad stock market, and investors expect a return lower than that expected 7 of the market. Reviewing the high and low beta.coefficients observed in the proxy group 8 provides a picture of the range that the new company could exhibit in the future.
, Beta Coefficients, Starrs Proxy Group ,
Updated on May 10, 2018 i
18-WSEE-328-RTS I
_ :Allete me ____ _ )_!.LE __ 0.75/--
_ _.~l}i!lf!t EnergyS<?_l))_ :LNT 0.701
- i\tner~n_g~gJ__ _ _ AEE 0.65' American Electric Power Co me AEP Q.65
- _
. Consolidated Edison me __ ,ED __ -0.50!
__ :'._J_ __
-- :~uke E}!e.r_g_y C~~_!-J~w
- Edison mternational ---- -- -
,DUK
'iix- Q:m-*
0.60, El Paso -Electric --- --
Co EE 0.75 IDACORP me IDA 0:7Q:_
NorthWe~~ern_ Corp NWE 0.6?;
- _C?Q~~~~r_g_y_g~p*_ - - OGE 0.95:
_Pinnacle West Capital_ Cofl} __ PNW 0.65:
,l:'_ortland General ~lectric Co POR 0.65:
Xcel Energy me ,XEL 0.60:
,Min 0.50:
- ----l
,Max 0.95:
+-
,Mean 0.671 0.65!
-1 we~~~- ----------- ---- 1- ---- ---
--IS-o~c~-: Valu;-ii~e-Investm~nt Survey -- --- -
9 I' 10 Q. Please describe the forecasted CAPM analysis.
54
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 A. For the forecasted CAPM, I relied on the expected returns published by JPMAM in its 2 annual publication, Long-Term Capital Market Assumptions for 2018, to establish the 3 expected return for the market. JPMAM publishes 10 to 15-year forecasts of expe"cted 4 returns on dozens of investment asset classes in its annual publication, the Long Term 5 Capital Market Return Assumptions (LTCMRA). JPMAM forecasts an animal return on 6 common stocks of 6.93%. The JPMAM's forecasted returns on common stocks has 7 declined over the past two years; generally a product of the increase in stock prices over 8 the past two years.
9 Following the calculations arid inputs through the CAPM equation in line 2 of the following 10 table, the forecasted return on a risk-free investment, 10-Year U.S. Treasury Bonds, is 11 subtracted from the- expected return on common stocks resulting in a risk premium of 12 3.86%. This risk premium is the additional return necessary to induce investors to take on 13 the added risk associat~d with common stocks over the risk-free investment. The beta 14 coefficient is applied to the risk premium to ascertain how much of a risk premium is 15 necessary for investors to take on risks of investing in utility stocks as opposed to the risk-16 free U.S. Treasury Bond.
55
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS
+J---- -- - - _J___ ------ --__ __;_ _-- - _J___ --- ----- l _____ ----- - l_ -- - _ _J_
i
- u~:t:!1sfs::::~:. !~t::::c;::~:!::~i::~
- f --j-~~~-=--~-- __ __ _ -=- -~=---=-~:----
0 18-"'.SEE-32~}!TS _ ---:- -~---=~ ~- ~1~__________ :j l
_ -----~------------~-----J-!
- 1) Forecasted Returns on Common Stocks L o w ~ - HighBeta 6.93%1 6.93%j 1- AvgBe-;f 6.93%1
- 2) Forecasted Total Return on 10-Year T-Bonds ,--- . -! ---- -3.07%f . 3.07%\ 3.07%1 3);ResultingRiskPremillll:'-- _______________________ ! _3.86%1
- _ _ 3.86%1 ____ 3.86%~
~'!l!Beta Coefficient ____ *__ _____ ___ __ _ x1 0.50 0.95 I 0.67 I ill_RiskPremium ___ .. _! ____ . ___ ___ . 1.93%1- __ 3.67o/4_ _ _ ~.59%1 __
i6)iForecasted Yield on lO~Year T-Bonds ____
- __ +1 3.50% 1 3.50%: 350%\
1)1_1'~ ~~~_!]?_g_ujt_y , .. _ __ _ _ ___ ... ~43%1___ 7.17'Yo~_ _6.02~
1I I
1 :
- 6.30%
. r -
_I I ! I I I
_j l)!Forecasted 10 to 15-year annual arithmetic return on stocks _ --"*-**- i
. _'.. _, for mid-sized col11J}aniesby J.P. MJrrgan Asset Management, 2018 E ~
- t-
_J_
l j_2) Forecasted_ 10 to 15-year annual arithmetic return on intermediate term 1
_(__iU.S. Government bonds by J.P. MorganAssetManageiyent, 2018 Edition , i l3)JResultingriskpremium(l-2) 1
- +
I 0
'4) B;~-co-;ffi~ient range olpro;.y group reported by Value-Line :
---c----------------- ---------------- ...
- 5): Row 3 x Row 4 = asset specific risk premium '
_jj:yorec~sted_yield on IO-Year U.S. Treasury bonds foreca~d by _____ ' - - -- _l_
.:.JrJ.P. Morg11Il Asset Management, 2018 Edition (page ?5J _ _ __~-- .. *I*
. ,7). Forecasted cost of equity capital row 5 + row 6 , * : I
. I I I I
-~':!_llfces:__ _ _ _ .. _ _ _ _
_ J.P. Morgan Asset Management, Long-term Capjtal Market Return Assumptions,
_ 2018 Edition; J.P. Morgan Asset Management (published October of2017) ..
- www.jprr.io~%°:n~~::tit_'-!ti_~~al.~o~(P_~./5es1jpmorg~n/a'!1/ia/r=;~_arch and 8.u_bl_ication~{l~mg-t~rm ~~Rital market
- ! I 1 1
2 The expected risk-free yield of 3.50% forecasted by JPMAM is added to the beta specific 3 risk premium to arrive at the cost of equity for the given beta coefficient of 0. 70 - about 60 4 basis points less than the returns JPMAM is forecasting for the broad stock market indexes.
5 These results appear low by historic measures of the past 40 years. The results are in line 6 with the returns offered on other investments in the current capital markets. For instance, 7 investors in Applicants' long-term bonds are purchasing bonds with the expectation for.
8 returns of less than 4.00%.
9 Q. Please discuss the historical CAPM analysis.
10 A. I performed a CAPM analysis incorporating historic data of returns earned from 1926 56
Direct Testimony of Adam H. Gatewood Docket No. 18-WSEE-328-RTS 1 through 2014. The process is the same as that applied in the Forecasted CAPM.
+-_J_ ___ _L____ I I I I I ____ __J_ I
- +~~--* l~WSE"328.lS~~~~~~1;~~-
!------- _______Capital Asset Pricing Model -- Historic Risk Premium fl J__ Based on Historic Risk Premiums from 1926 to 2015
+=t=-~i==
+-
- 1 1 . - . . - . -*** - - -- * -- .
+ l)!Total Returns on Common Stocks
~/Total ReturnonGovernmentBonds __ .--- ________ I
- _------+--~_}2.10%1 _____ _12.10%1
-1 5.20%1 5.20%1
_ 12.10%1 5.20%1_
t-=~::~~!re7tun _______ ---~-- -----------1----J--- 6:.~~I ~~-~------~o~
_I_ 5)/RiskPremitun ___ ; ___________ *________ J _____ : _3.45%! _ __6.56%'. 4.6~__
! 6),Historic Yield on Government Bonds * ! +! 4.38%1 4.38%1 4.38%1
~;~-- ?)_lfore£_a~~~d. Costof~quityBased onHi~toricReturns -I ----i--- _
7.83~ _______ !.Q.93%f __ .2.:_Q_0%r 9.38% '
\ I ,
'-----~-- __ 1__- _ *t__*_---_____ :*-_____ i ..
- r _ _ r--_---____ :__ _
~ .. - - - --. .. ,.'
I
- -: I) !Historic I returns
. on common stocks 1926-2017- (SBBI; Exhibit 2-3) .. -----
! 2) IHistoric returns on intermediate-term government bonds 1926-2017 :
L-~~ultiE_g risk premitun (1-2) _ *~ l--~~~-~:~ _:_:_:-_ ... -.... :~:-~:- _ _r.
.l. _4) JBeta coefficient of the proxy group (Reported by Value-Line)_ _ _ _; .. _ _ _ _ __ ___ _ __ _,__
- _2)fRow 3~ xRow ~ =~set Specific RiskPremitun ~ - - - - 1 _____ _1._ _ _____.__
-~ __&~ Hist~ic year-end yiel~ on int_ermediate-term governm~~ds ! 926:~! ?__ _ , ____ _
-~:- -~~~recast~~ co.st ~T~=~-~~~~~:~ _5:_ro~ 6_ . *L*--r_ _ __:'.: _..
,Sources: ~----:______ . _________ .______________________ _
,Ibbotson SBBI: 2018 Classic Yearbook(Duff& Phelps) & Value-Line Investment Survey
' ' .- - i- --_ ; . . -,
2 j I I I I : . I 3 In relying on purely historic data, we are assuming that certain trends observed in the past 4 80 years will continue in the future. Most notably, we would be assuming that the returns.
5 observed on common stocks from decades past will continue in the* future, which of course 6 assumes this historical data accurately measures the past returns. There is strong evidence 7 that these frequently-quoted returns do not present a complete picture of historic* returns. 35 8 .The simple step of beginning measurement period in 1926 brings questions as to whether 9 the time period represents all of the modern-era securities trading. The historic returns are 10 reported and might influence expectations despite warnings that surround historic 35 McQ~arrie, Edward F; "The Myth of 1926: How Much Do We Know Long-Term Returns on U.S. Stocks?"; The Journal oflnvesting; Winter 2009; p. 96.
57
Direct Testimony of Adam H. Gatewood DocketNo. 18-WSEE-328-RTS 1 economic growth rates. There are well regarded financial publications that focus solely on 2 this type of historic data and how to apply it in cost of capital studies. Thus, I have to argue 3 that the historic data is. part of the cost of capital universe, although given only light 4 consideration in the final decision.
5 Q. Does that conclude your testimony?
6 A. Yes, thank you.
58
Schedule AHG - 1 18-WSEE-328-RTS DECON--With Long-Term Spent Fuel Management Costs KCC Staffs Primary Recommendation in 18-WCNE-107-GIE
- $ 7,793,513 Annual Payment Annual Annual Annual Annual Time Year Inflow Outflow Earnings Balance Return 1 2018 $ 7,793,513 $ - $ 237,154,291 4.20%
2 2019 $ 7,793,513 $ - $ 10,114,502 $ 255,062,306 4.20%
3 2020 $ 7,793,513 $ - $ 10,865,922 $ 273,721,741 4.20%
4 2021 $ 7,793,513 $ - $ 11,648,872 $ 293,164,126 4.20%
5 2022 $ 7,793,513 $ - $ 12,464,675 $ 313,422,313 4.20%
6 2023 $ 7,793,513 $ - $ 13,314,708 $ 334,530,534 4.20%
7 2024 $ 7,793,513 $ - $ 14,200,409 $ 356,524,456 4.20%
8 2025 $ 7,793,513 $ - $ 15,123,274 $ 379,441,243 4.20%
9 2026 $ 7,793,513 $ - $ 16,084,862 $ 403,319,618 4.20%
10 2027 $ 7,793,513 $ - $ 17,086,799 $ 428,199,930 4.20%
11 2028 $ 7,793,513 $ - $ 18,130,777 $ 454,124,220 4.20%
12 2029 $ 7,793,513 $ - $ 19,218,560 $ 481,136,293 4.20%
13 2030 $ 7,793,513 $ - $ 20,351,987 $ 509,281,792 4.20%
14 2031 $ 7,793,513 $ - $ 21,532,972 $ 538,608,277 4.20%
15 2032 $ 7,793,513 $ - $ 22,763,511 $ 569,165,301 4.20%
16 2033 $ 7,793,513 $ - $ 24,045,684 $ 601,004,497 *4.20%
17 2034 $ 7,793,513 $ - $ 25,381,657 $ 634,179,667 4.20%
18 2035 $ 7,793,513 $ - $ 26,773,687 $ 668,746,866 4.20%
19 2036 $ 7,793,513 $ - $ 28,224,126 $ 704,764,505 4.20%
20 2037 $ 7,793,513 $ - $ 29,735,427 $ 742,293,444 4.20%
21 2038 $ 7,793,513 $ - $ 31,310,141 $ 781,397,098 4.20%
22 2039 $ 7,793,513 $ - $ 32,950,930 $ 822,141,541 4.20%
23 2040 $ 7,793,513 $ - $ 34,660,567 $ 864,595,621 4.20%
24 r2041 $ 7,793,513 - $ - $
- 36,441,940 $ 908,831,074 4.20%
25 2042 $ 7,793,513 $ - $ 38,298,060 $ 954,922,646 4.20%
26 2043 $ 7,793,513 $ - $ 40,232,062 $ ' . 1,002,948,221 4.20%
27 28 29 2044 2045 2046 7,793,513 $
(78,411,865)
(169,068,348) 42,247,215 44,183,416 42,747,191 1,052,988,949 1,018,760,500 892,439,343 4.20%
4.20%
4.20'l;o 30 2047 $ - $ (183,090,767) $ 37,446,755 $ 746,795,331 4.20%
31 2048 $ - $ (156,256,606) $ 26,455,673 $ 616,994,398 3.54%
32 2049 $ - $ (127,910,434) $ 21,857,397 $ 510,941,361 3.54%
33 2050 $ - $ (117,066,127) $ 18,100,404 $ 411,975,638 3.54%
34 2051 $ - $ (71,555,507) $ I 14,594,484 $ 355,014,615 3.54%
35 2052 $ - $ (54,464,502) $ 12,576,606 $ 313,126,718 3.54%
36 2053 $ - $ (38,482,991) $ 11,092,702 $ 285,736,429 3.54%
37 2054 $ - $ (12,722,791) $ 10,122,384 $ 283,136,022 3.54%
38 2055 $ - $ (13,093,025) $ 10,030,263 $ 280,073,261 3.54%
39 2056 $ - $ (13,511,435) $ 9,921,763 $ 276,483,589 3.54%
40 2057 $ - $ (13,866,126) $ 9,794,597 $ 272,412,060 3.54%
41 2058 $ - $ (14,269,630) $ 9,650,361 $ 267,792,790 3,54%
42 2059 $ - $ (14,684,876) $ 8,165,752 $ 261,273,666 3.05%
43 2060 $ - $ (15,154,158) $ . 7,966,966 $ 254,086,474 3.05%
44 2061 $ - $ (15,551,972) $ 7,747,808 $ 246,282,310 3.05%
45 2062 $ - $ (16,004,534) $ 7,509,837 $ 237,787,613 3.05%
46 2063 $ - $ (16,470,266) $ 7,250,810 $ 228,568,158 3.05%
47 2064 $ - $ (16,996,602) $ 6,969,683 $ 218,541,238 3.05%
48 2065 $ - .$ (17,442,782) $ 6,663,934 $ 207,762,390 3.05%
49 2066 $ - $ (17,950,367) $ 6,335,257 $ 196,147,280 3.05%
50 2067 $ - $ (18,472,723) $ 5,981,080 $ 183,655,636 3.05%
51 206~ $ - $ (19,063,052) $ 5,600,175 $ 170,192,759 3.05%
52 2069 $ - $ (19,563,479) $ 5,189,654 $ 155,818,934 3.05%
53 2070 $ - $ (20,132,776) $ 2,676,969 $ 138,363,128 1.72%
54 2071 $ - $ (20,718,640). $ 2,377,079 $ 120,021,567 1.72%
55 2072 $ - $ (21,380,741) $ 2,061,971 $ 100,702,797 1.72%
56 2073 $ - $ (21,942,009) $ 1,730,074 $ 80,490,862 1.72%
57 2074 $ - $ (58,404,136) $ 1,382,833 $ 23,469,559 1.72%
58 2075 $ - $ (23,872,766) $ 403,207 $ 0 1.72%
Schedule AHG - 1 18-WSEE-328-RTS SAFESTOR KCC Staffs Alternative Recommendation in 18-WCNE-107-GIE
$ 8,693,911 Annual Payment Annual Annual Annual Annual Time Year Inflow. Outflow Earnings Balance Return 1 2018 $ 8,693,911 $ $ 237,154,291 4.20%
2 2019 $ 8,693,911 $ $ 10,133,392 $ 255,981,594 4.20%
3 2020 $ 8,693,911 $ $ 10,923,386 $ 275,598,891 4.20%
4 2021 $ 8,693,911 $ $ 11,746,528 $ 296,039,329 4.20%
5 2022 $ 8,693,911 $ $ 12,604,208 $ 317,337,448 4.20%
6 2023 $ 8,693,911 $ $ 13,497,878 $ 339,529,236 4.20%
7 2024 $ 8,693,911 $ $ 14,429,045 $ 362,652,192 4.20%
8 2025 $ 8,693,911 $ $ 15,399,284 $ 386,745,387 4.20%
9 2026 $ 8,693,911 , $ $ 16,410,235 $ 411,849,532 4.20%
10 2027 $ 8,693,911 $ $ 17,463,605 $ 438,007,047 4.20%
11 2028 $ 8,693,911 $ $ 18,561,174 $ 465,262,131 4.20%
12 2029 $ 8,693,911 $ $ 19,704,797 $ 493,660,839 4.20%
13 2030 $ 8,693,911 $ $ 20,896,407 $ 523,251,157 4.20%
14 2031 $ 8,693,911 $ $ 22,138,017 $ 554;083,084 4.20%
15 2032, $ 8,693,911 $ $ 23,431,724 $ 586,208,719 4.20%
16 . 2033 $ 8,693,911 * $ $ 24,779,716 $ 619,682,346 4.20%
17 2034 $ 8,693,911 $ $ 26,184,269 $ 654,560,526 4.20%
18 2035 $ 8,693,911 $ $ 27,647,758 $ ,690,902, 195 4.20%
19 2036 $ 8,693,911 $ $ 29,172,654 $ 728;768,759 4.20%
20 2037 $ 8,693,911 $ $ 30,761,535 $ 768,224,205 4.20%
21 2038 $ . 8,693,911 $ $ 32,417,086 $ 809,335,202 4.20%
22 2039 $ 8,693,911 $ $ 34,142,103 $ 852,171,216 4.20%
23 2040 $ 8,693,911 $ $ 35,939,502 $ 896,804;629 4.20%
24 2041 $ 8,693,911 $ $ 37,812,320 $ 943,310,860 4.20%
25 2042 $ 8,693,911 $' $ 39,763,722 $ 991,76,8,492 4.20%
26 2043 $ 8,693,911 $ $ 41,797,004 $ 1,042,259,407 4.20%
27 28 2044 2045 8,693,911 $
$ (63,088,403) 43,915,603 45,940,700 $
1,094,868,92 I 1,077,721,218 4.20%
4.20%
29 2046 $ $ (90,464,645) $ 45,221,182 $ 1,032,477,755 4.20%
30 2047 $ $ (41,393,404) $ 43,322,767 $ 1,034,407,117 4.20%
31 2048 $ $ (42,593,23J) $ 43,403,723 $ 1,035,217,603 4.20%
32 2049 $ $ (43,584,004) $ 43,437,731 $ 1,035,071,330 4.20%
33 2050 $ $ (32,822,082) $ 43,431,593 $ 1,045,680,841 4.20%
34 2051 $ $ (6,098,522) $ 43,876,768 $ 1,083,459,087 4.20%
35 2052 $ $ (6,275,776) $ 45,461,943 $ 1,122,645,254 4.20%
36 2053 $ $ (6,425,023) $ 47,106,195 $ 1,163,326,426 4.20%
37 2054 $ $ (6,594,873) $ 48,813,177 $ 1,205,544,730 4.20%
38 2055 $ $ (6,769,285) $ 50,584,657 $ 1,249,360,102 4.20%
39 2056 $ $ (6,966,308) $ 52,423,150 $ 1,294,816,944 4.20%
40 2057 $ $ (7,132,295) $ 54,330,519 $ 1,342,015,168 4.20%
41 2058 $ $ (7,321,154) $ 56,310,956 $ 1,391,004,971 4.20%
42 2059 $ $ (7,515,094) $ 58,366,569 $ 1,441,856,445 4.20%
43 2060 $ $ (7,734,135) $ 60,500,296 $ 1,494,622,606 4.20%
44 2061 $ $ (7,918,782) $ 62,714,365 $ 1,549,418,188 4.20%
45 2062 $ $ (8,128,821) $ 65,013,587 $ 1,606,302,954 4.20%
46 2063 $ $ (8,344,524) $ 67,400,472 $ 1,665,358,902 4.20%
Schedule AHG - 1 18-WSEE-328-RTS.
SAFESTOR KCC Staffs Alternative Recommendation in 18-WCNE-107-GIE
$ 8,693,911 Annual Payment Annual Annual Annual Annual Time Year Inflow Outflow Earnings . Balance Return 47 2064 $ . $ (8,588,097) $ 69,878,460 $ 1,726,649,265 4.20%
48 2065 $ $ (8,793,550) $ 72,450,203 $ 1,790,305,918 4.20%
49 2066 $ $ (9,027,198) $ 75,121,236 $ 1,856,399,956
- 4.20%
50 2067 $ $ (9,267,161) $ 77,894,542 $ 1,925,027,337 . 4.20%
51 2068 $ $ (9,538,074) $ 80,774,147 $ 1,996,263,410 4.20%
52 2069 $ $ (9,766,735) $ 83,763,213 $ 2,070,259,888 4.20%
53 2070 $ $ (10,026,710) $ 86,868,105 $ 2,147,101,282 4.20%
54 2071 $ $ (10,293,728) $ 90,092,370 $ 2,226,899,924 4.20%
55 2072 $ . $ (10,595,124). $ 93,440,721 $ 2,309,745,521 4.20%
56 2073 $ $ (10,849,682) $ 96,916,922 $ 2,395,812,761 4.20%
57 2074 $ $ (11,139,026) $ I 00,528,303 $ 2,485,202,038 4.20%
58 2075 $ .$ (11,436,229) $ 104,279,078 $ 2,578,044,887 4.20%
59 2076 $ $ (11,771,622) $ 108,174,763 $ 2,674,448,029 . 4.20%
60 . 2077 $ $ (12,055,094) $ 112,219,839 $ 2,774,612,775 4.20%
61 2078 $ $ (12,377,214) $, 116,422,752 $ 2,878,658,313 4.20%
62 2079 $ $ (12,708,107) $ 120,788,503 $ 2,986,738,709 4.20%
63 2080 $ - "$ (13,081,436) * $ 125,323,556 $ 3,098,980,829 4.20%
64 2081 $ $ (13,397,204) $ 130,033,236 $ 3,215,616,861 4.20%
65 2082 $ $ (13,755,921) $ 134,927,283 $ 3,336,788,223 4.20%
66 2083 $ $ (14,124,437) $ 140,011,634 $ 3,462,675,421 4.20%
67 2084 $ . *$ (14,540,115) $ 145,293,861 $ 3,593,429,166 4.20%
68 2085 $ $ (14,891,978) $ 127,299,384 $ 3, 705;836,572 3.54%
69 2086 $ $ . (15,291,579) $ 131,281,484 $ 3,821,826,478 3.54%
- 70 2087 $ $ (15,702,131) $ 135,390,496 $ 3,941,514,843 3.54%
71 2088 $ $ (16,165,110) $ 139,630,528 $ 4,064,980,262 3.54%
72 2089 $ $ (16,557,336) $ 144,004,365 $ 4,192,427,290 3.54%
73 2090 $ $ (17,002,637) $
- 148,519,252 $ 4,323,943,905 3.54%
74 2091 $ $ (17,460,184) $ 153,178,307 $ 4,459,662,029 3.54%
75 2092 $ $ (17,976,023) $ 135,987,582 $ 4,577,673,588 3.05%
76 2093 $ $ (18,413,418) $ 139,586,085 $ 4,698,846,255 3.05%
77 2094 $ $ (18,909,833) $ 143,280,979 $ 4,823,217,401 3.05%
78 2095 $ $ (19,419,952) $ 147,073,404 $ 4,950,870,853 3.05%
- 79 2096 $ $ (19,994,901) $
- 150,965,915 $ 5,081,841,867 3.05%
80 *
- 2097 $ $ (20,482,876) $ 154,959,588 $ 5,216,318,578 3.05%
81 2098 $ $ (42,997,311) $ 89,616,353 $ 5,262,937,620 1.72%
82 2099 $ $ (202,494,640) $ 90,417,268 $ 5,150,860,248 1.72%
83 2100 $ $ (1,251,269,068) $ 88,491,779 $ 3,988,082,959 1.72%
84 2101 $ $ (1,843,454,798). $ 68,515,265 $ 2,213,143,426 1.72%
85 2102 $ $ (781,487,440) $ 38,021,804 $ 1,469,677,790 1.72%
86 2103 $ $ (818,350,434) $ 25,249,064 $ 676,576,420 1.72%
87 2104 $ $ (459,929,593) $ 11,623,583 $ 228,270,410 1.72%
88 2105. $ $ (141,421,602) $ 3,921,686 $ 90,770,493 1.72%
89 2106 $ $ (92,329,930) $ 1,559,437 $ (0) 1.72%
Schedule AHG - 2 18-WSEE-328-RTS Estimates of Returns on Nuclear Decommissioning Trusts Across Investment Periods JPMAM Long-Term Capital Market Assumptions Pre-Tax 2017 2018 Asset Proj. Weighted After Arithmatic Geometric Arithmatic Geometric Time Period 1 Weight Return Return Tax Equities-Large Cap 7.63% 6.25% 6.41% 5.50% Equities-Large Cap 27.00% 6.41% 1.73% 1.38%
Equities-Small Cap 8.67% 7.00% 7.35% 5.75% Equities-Small Cap 6.00% 7.35% 0.44% 0.35%
Equities-International (EAFE) 7.95% 6.75% 7.61% 6.25% Equities-International (EAFE) 20.00% 7.61% 1.52% 1.22%
Core Bonds 3.44% 3.25% 3.67% 3.50% Core Bonds 25.00% 3.67% 0.92% 0.73%
High Yield Bonds 6.13% 5.75% 5.59% 5.25% High Yield Bonds 17.00% 5.59% 0.95% 0.76%
Real Estate 7.32% 6.00% 7.42% 6.25% Real Estate 5.00% 7.42% 0.37% 0.30%
Cash & Equivalents 2.00% 2.00% 2.00% 2.00% Cash & Equivalents 0.00% 2.00% 0.00% 0.00%
Management Fees 0.55% Time Period 2 Tax Rate 20.00% Equities-Large Cap 20.00% 6.41% 1.28% 1.03%
Equities-Small Cap 5.00% 7.35% 0.37% 0.29%
DECON Methodology 2018-2053 Equities-International (EAFE) 12.00% 7.61% 0.91% 0.73%
Pre-Tax Post-Tax Core Bonds 44.00% 3.67% 1.61% 1.29%
Time Period I 2017-2025 5.93% 4.20% High Yield Bonds 8.00% 5.59% 0.45% 0.36%
Time Period 2 2026-2035 5.12% 3.54% Real Estate 5.00% 7.42% 0.37% 0.30%
Time Period 3 2036-2044 4.50% 3.05% Cash & Equivalents 6.00% 2.00% 0.12% 0.10%
Time Period 4 2045-2053 2.84% 1.72%
Time Period 3
- DECON-Alt (Appendix E) Methodology 2018-2075 Equities-Large Cap 10.00% 6.41% 0.64% 0.51%
Pre-Tax Post-Tax Equities-Small Cap 5.00% 7.35% 0.37% 0.29%
Time Period 1 2017-2047 5.93% 4.20% Equities-International (E~E) 5.00% 7.61% 0.38% 0.30%
Time Period 2 2048-2058 5.12% 3.54% Core Bonds 57.00% 3.67% 2.09% 1.67%
Time Period 3 2059-2069 4.50% 3.05% High Yield Bonds 8.00% 5.59% 0.45% 0.36%
Time Period 4 2070-2075 2.84% 1.72% Real Estate 5.00% 7.42% 0.37% 0.30%
Cash & Equivalents 10.00% 2.00% 0.20%- 0.16%
SAFESTOR Methodology 2018-_2106 Pre-Tax Post-Tax Time Period 4 Time Period 1 2017-2075 5.93% 4.20% Equities-Large Cap 0.00% 6.41% 0.00% 0.00%
Time Period 2 2076-2086 5.12% 3.54% Equities-Small Cap 0.00% 7.35% 0.00% 0.00%
Time Period 3 2087-2097 4.50% 3.05% Equities-International (EAFE) 0.00% 7.61% 0.00% 0.00%
Time Period 4 2098-2106 2.84% 1.72% Core Bonds 50.00% 3.67% 1.84% 1.47%
High Yield Bonds 0.00% 5.59% 0.00% 0.00%
Sources: J.P.Morgan Asset Management 2018 & 2017 Long-term Asset Returns Real Estate 0.00% 7.42% 0.00% 0.00%
Management fees estimated by Applicant; Susan M. McGrath Direct Testimony Cash & Equivalents 50.00% 2.00% 1.00% 0.80%
18-WSEE-328-RTS; Filed February I, 2018.
18-WSEE-328-RTS AMEREN NYSE-AEE . RECENT PRICE 53 ,94 IP/ERATIO 171erailing:19.4)
, Median: 15.0 RELATIVE PIE RATIO O93 DIV'D I YLD 3.5%-
TIMELINESS 2 Raised 3/2/18 High: 55.0 54.3 35.3 29.9 34.1 35.3 37.3 48.1 46.8 54.1 64.9 59.0 Target Price Range Low: 47.1 25.5 19.5 23.1 25.5 28.4 30.6 35.2 37.3 41.5 51.4 51.9 2021 2022 2023 SAFETY 2 Raised 6/20/14 LEGENDS TECHNICAL 3 Lowered 2/23/18 - ~::d~vi1;t~1:sf ~~te
, . , . Relative ~rice Strength 80 BETA .65 (1.00 = Market) .,,.._
- --... *-- . ' ,. 60 1,111 O~~~~!/i,~a indicates recession ,...__ 50 2021-23 PROJECTIONS Ann'I Total ....:_.:: ~..*}..... n "- I - J__./ 11
/
11111* 1 .. 1*'!11111'*
,. f'T';.
. *-111 1
40 Price Gain Return I I 11* 1 1,**111*1 30
- I I High 60 (+10%l 6% 25 Low 45 (-15% Nil I 'Ith,
...... ..**** .... ......... ... 20 Insider Decisions I l .... 15 MJJASO N D J to Buy 000000 o o o Options 010000 0 021 I l ****** 10 tos,u 0 1 0 0 0 0 1 0 0 I I 1-7.5
% TOT. RETURN 2/18 I ..
Institutional Decisions THIS I 11 I 11, .. VLARITH.'
- m*m I~
2Q2017 3Q2017 4Q2017 Percent STOCK INDEX 15 1 yr. 2.4 10.1 I-to Buy 212 shares
~~r 247 229 10 tos,u 209 215 192 traded 5 Ill"' 3yr. 42.4 24.2 ~
Hld's!OOO 185587 186752 171005 11111111,I 5yr. 94.9 76.2 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 © VALUE LINE PUB. LLC 1-23 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 25.13 25.04 25.46 25.20 25.85 Revenues per sh 28.00 5.28 6.29 5.51 6.10 6.02 6.76 6.44 6.06 6.33 5.87 5.87 5.25 5.77 6.08 6.59 6.80 7.35 7.85 "Cash Flow" per sh 9.25 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 2.38 2.68 2.77 3.05 3.25 Earnings per sh A 3.75 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 1.66 1.72 1.78 1.85 1.93 Div' d Deel' d per sh a
- 2.25 5.11 4.19 4.13 4.63 4.99 6.96 9.75 7.51 4.66 4.50 5.49 5.87 7.66 8.12 8.78 9.05 9.80 10.45 Cap'I Spending per sh 8.50 24.93 26.73 29.71 31.09 31.86 32.41 32.80 33.08 32.15 32.64 27.27 26.97 27.67 28.63 29.27 29.61 31.00 32.45 Book Value per sh c 37.25 154.10 162.90 195.20 204.70 206.60 208.30 212.30 237.40 240.40 242.60 242.63 242.63 242.63 242.63 242.63 242.63 244.00 245.50 Common Shs Outst'g o 250.00 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 17.5 18.3 20.6 Bold fig res are Avg Ann'I P/E Ratio 14.5
.86 .77 .86 .89 1.05 .92 .85 .62 .62 .75 .85 .93 .88 .88 .96 1.02 Value Line Relative P/E Ratio .80 6.1% 6.0% 4.9% 4.9% 4.9% estln ates 5.5% 6.2% 6.0% 5.8% 5.3% 5.0% 4.6% 4.0% 4.0% 3.5% 3.1% Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUCTURE as of 12/31/17 7839.0 7090.0 7638.0 7531.0 6828.0 5838.0 6053.0 6098.0 6076.0 6177.0 6150 6350 Revenues ($mill) 7000 Total Debt $8419 mill. Due in 5 Yrs $2862 mill. 615.0 624.0 669.0 602.0 589.0 518.0 593.0 585.0 659.0 683.0 755 805 Net Profit ($mill) 950 LT Debt $7094 mill. LT Interest $348 mill.
(LT interest earned: 4.2x) 33.7% 34.7% 36.8% 37.3% 36.9% 37.5% 38.9% 38.3% 36.7% .38.2% 22.0% 22.0% Income Tax Rate 22.0%
Leases, Uncapitalized Annual rentals $1 Omill. 4.6% 5.8% 7.8% 5.6% 6.1% 7.1% 5.7% 5.1% 4.1% 3.5% 4.0% 4.0% AFUDC %to Net Profit 3.0%
Pension Assets-12/17 $4293 mill. 47.8% 49.7% 48.2% 45.3% 49.5% 45.2% 47.2% 49.3% 47.7% 49.2% 49.5% 49.0% Long-Term Debt Ratio 49.5%
Obllg $4827 mill. 50.8% 49.1% 50.9% 53.7% 49.4% 53.7% 51.7% 49.7% 51.3% 49.8% 49.5% 50.0% Common Equity Ratio 50.0%
Pfd Stock $142 mill. Pfd Div'd $6 mill. 13712 15991 15185 14738 13384 12190 12975 13968 13840 14420 15225 15925 Total Capital ($mill) 18600 807,595 sh. $3.50 to $5.50 cum. (no par), $100 16567 17610 17853 18127 16096 16205 17424 18799 20113 21466 22800 24225 Net Plant ($mill) 27100 stated val., redeem. $102.176-$110/sh.; 616,323 sh. 4.00% to 6.625%, $100 par, redeem. $100- 5.7% 5.3% 6.0% 5.6% 6.0% 5.6% 5.8% 5.3% 6.0% 5.9% 6.0% 6.0% Return on Total Cap'I 6.5%
$104/sh. 8.6% 7.8% 8.5% 7.5% 8.7% 7.7% 8.7% 8.3% 9.1% 9.3% 10.0% 10.0% Return on Shr. Equity 10.0%
Common Stock 242,634,798 shs. as of 1/31/18 8.7% 7.8% 8.6% 7.5% 8.8% 7.8% 8.7% 8.3% 9.2% 9.4% 10.0% 10.0% Return on Com Equitv E 10.0%
MARKET CAP: $13 billion (Large Cap) 1.0% 3.5% 3.8% 2.8% 3.0% 1.9% 2.9% 2.5% 3.3% 3.4% 4.0% 4.0% Retained to Com Eq 4.0%
ELECTRIC OPERATING STATISTICS 88% 56% 56% 63% 66% 76% 67% 70% 64% 64% 61% 60% All Div'ds to Net Prof 60%
2015 2016 2017 BUSINESS: Ameren
%Cha~e Retail Sa~s (Kl'ili) -1.1 -4.2 -3.4 Corporation is a holding company formed dustrial, ~%; other, 11%. Generating sources: coal, 71%; nuclear, Avg. In ust Use (M,'IHJv.m NA NA NA through the merger of Union Electric and CIPSCO. Acq'd CILCORP 19%; hydro & other, 4%; purchased, 6%. Fuel costs: 27% of revs.
Avg. lndust Revsi (¢) NA NA NA 1/03; Illinois Power 10/04. Has 1.2 mill. electric and 127,000 gas '17 reported deprec. rates: 3%-4%. Has 8,600 employees. Chair-Capati1y at Peak ~ NA NA NA customers in Missouri; 1.2 mill. electric and 813,000 gas customers man, President & CEO: Warner L Baxter. Inc.: MO. Address: One Peak Load, Summer~ ) NA NA NA Annual load Factor(,~ NA NA NA in Illinois. Discontinued nonregulated power-generation operation in Ameren Plaza, 1901 Chouteau Ave., P.O. Box 66149, St Louis,
%Change Cu~omers r-end) NA NA NA '13. Electric rev. breakdown: residential, 46%; commercial, 35%; in- MO 63166-6149. Tel.: 314-621-3222. Internet: www.ameren.com.
F~ed Charge Cov. (%) 343 351 362 We think Ameren's earnings will ex- cates profit growth of 7%, which is within ANNUAL RATES Past Past Est'd '15-'17 ceed the $3.00-a-share level in 2018. management's annual goal of 5%~7%.
of change (per sh) 10Yrs. 5Yrs. to '21-'23 The company will benefit from a full year's Will 2018 be the year in which a regu-Revenues -3.0% -3.5% 2.0% effect of the rate increase that took effect lato:ry law is passed in Missouri? Utili-
"Cash Flow" .5% 1.5% 6.5% in Missouri at the start of April of 2017. A ties in the state have been hurt by regu-Earnings -1.0% .5% 7.5%
Dividends -4.0% 2.0% 4.5% return to normal weather patterns would latory lag because Missouri uses a histori-Book Value -1.0% -1.0% 4.0% help after unfavorable weather was a drag cal test year and doesn't use a lot of me-Cal- QUARTERLY REVENUES !$ mill.) on profits last year. The Callaway nuclear chanisms that allow for concurrent re-Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year facility will not have a refueling outage covery of certain kinds of capital spending 2015 1556 1401 1833 1308 6098.0 this year. The refinancing of debt will or expenses. The state senate has passed a 2016 1434 1427 1859 1356 6076.0 boost earnings. Our earnings estimate is bill that would be beneficial for utilities in 2017 1514 1538 1723 1402 6177.0 at the midpoint of Ameren's targeted this regard. If the bill is enacted into law, 2018 1500 1500 1750 1400 6150 range of $2.95-$3.15 a share. Note that the Ameren will boost its capital spending in 2019 1550 1550 1800 1450 6350 201 7 tally was depressed by the revalua- the state, with an estimated $1 billion for Cal- EARNINGS PER SHARE A Full tion of deferred taxes, which stemmed grid modernization through 2023.
endar Mar.31 Jun.30 Sep.30 Dec.31 Year from the new federal tax law. This forced Ameren filed a gas rate application in 2015 .45 .40 1.41 .12 2.38 Ameren to take a nonrecurring charge of Illinois. The utility requested a $49 mil-2016 .43 .61 1.52 .13 2.68 $0.63 a share in the fourth fi.uarter. lion increase, based on a 10.3% return on a 2017 .42 .79 1.18 .39 2.77 We forecast further pro t growth in 50% common-equity ratio. A ruling is ex-2018 .55 .70 1.40 .40 3.05 2019. One factor that boosts Ameren's pected in late 2018, with new tariffs tak-2019 .60 .70 1.50 .45 3.25 earning power annually is the utility's in~ ing effect in January of 2019 .
Cal, QUARTERLY DIVIDENDS PAID a* Full vestment in electric transmission. There is This timely sto~k has a dividend yield endar Mar.31 Jun.30 Seo.30 Dec.31 Year still uncertainty about what the allowed that is about average, by utility stan-2014 .40 .40 .40 .41 1.61 return on equity will be-the Federal En- dards. Like many utility equities, the 2015 .41 .41 .41 .425 1.66 ergy Regulatory Commission must still is- recent quotation is within our 3- to 5-year 2016 .425 .425 .425 .44 1.72 sue a ruling on this-but this will still ex- Target Price Range. Accordingly, total re-2017 .44 .44 .44 .4575 1.78 ceed the allowed ROEs in Missouri and 11- turn potential over that time frame is low.
2018 .4575 linois. Our 2019 earnings estimate indi- Paul E. Debbas, CFA March 16, 2018 (A) Dil. EPS. Exel. nonrec. gain (losses): '05, ing. Next egs. report due early May. (B) Div'ds depr. Rate all'd on com. eq. in MO in '17: elec., Company's Financial Strength A (11¢); '10, ($2.19); '11, (32¢): '12, ($6.42); '17, histor. paid in late Mar., June, Sept., & Dec.* none spec.; in '11: gas, none spec.; in IL in '14: Stock's Price Stability 95 (63¢); gain (loss) from disc. ops.: '13, (92¢); Div'd reinv. plan avail. (C) Incl. intang. In '17: elec., 8.7%, in '16: gas, 9.6%; earned on avg. Price Grow1h Persistence 40
'15, 21 ¢. '16-'17 EPS don't sum due to round- $6.76/sh. (Dr In mill. (E) Rate base: Orig. cost com. eq., '17: 7.3%. Reg. Climate: Below Avg. Earnings Predic1ability 80
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THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of nmay be reproduced, resold, stored or t1ansmnted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, seivice or product
18-WSEE-328-RTS t--A_M_ER_l-,,---CA_N_E_L_E..--C._P-.-W_R---,-.N_YS__,E-A_EP~l~-,--~fJE_NT~6_5.---,-50~1~---,/ETlo_1_6.-,--5(_~~~~
3 Lowered High: 51.2 49.1 36.5 37.9 41.7 45.4 51.6 63.2 1 1
- ~t_m-+)~_TJARA_r16_0_.8-r-6'--~t~--,-D_3.~9°_Yo 65.4 71.3 78.1 73.4 iii1~**-----i Target Price Range TIMELINESS 1119118 Low: 41.7 25.5 24.0 28.2 33.1 37.0 41.8 45.8 52.3 56.8 61.8 63.3 2021 2022 2023 SAFETY 1 Raised 3/17117 LEGENDS TECHNICAL 3 Lowered 312118 - ~i~:d~vi1;t~~!sr ~~te 1 - - - + - - - - + - - - + - - - - + - - + - - - - + - - + - - - - + - - + - - - - + - - + - - - - + - - - + - - - - - + -128
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- Relative ~rice Strength t---+-----t---t----+--+--- -+--+----+--+----+--+--- -+--+----+-96 r High Low 2021-23 PROJEC1l_0N,fi; t B_E_TA~.6~5:(:1.0pjORJ==M~ark:e Price 80 (+20%1 65 Gain 'Wetu~a (Nil 4%
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P:~i:1r' l - - - + - -----t--'-llii.l-1----1----11----1----l-- ---l---1----l---l----l %TOT. RETURN 21,a Institutional Decisions I 1 . rnrs VLARITH.*
1 -'c-t-rlr.c~l---+---i 31 ~rr.. ST2~0:C~K 12~04D:EX21 r-~
2Q2017 3Q2017 4Q2017 Percent 15 1 1 1 1 1I I" ,., I I toBuy to Soll 376 369 388 351 Hld'slOOO 384520 382879 352776 ra e 342 tshares 371 d d 5 **
10 m* -
- l4UIIUIJU ll.l.UIJUllll 5 yr. 69.1 76.2
~
t-:2=oc:o-=-2'r-2=0=0=3..,.--:,20=0:-::4..,.--:,2=00=s=-+-=2=0=0s::-r::2:-:::0=01='""""200a 2009 2010 2011 2012 2013 2014 201s 201s 2011 2=0'"'1=a-+=20~1=9-+-@=,v=A'"'Lu=E'""uN=E=pu=e,.....L.,--:Lc,..,,,::r.1...,-2=3-1 42.96 36.82 35.51 30.76 31.82 33.41 35.56 28.22 30.01 31.27 30.77 31.48 34.78 33.51 33.31 31.35 30.60 31.30 Revenues per sh 33.00 6.99 5.76 5.89 5.96 6.67 6.80 6.84 6.32 6.29 6.83 6.92 7.02 7.57 7.98 8.47 7.95 8.30 8.60 "Cash Flow" per sh 9.50 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 3.59 4.23 3.62 3.90 4.10 Earnings per sh A 5.00 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 2.39 2.51 2.63 Div'dDecl'dpersh 8
- 105 5.08 3.44 4.28 6.11 8.89 8.88 9.83 6.19 5.07 5.74 .6.45 7.75 8.68 9.37 9.98 11.79 12.50 12.95 Cap'I Spending per sh 11.25 20.85 19.93 21.32 23.08 23.73 25.17 26.33 27.49 28.33 30.33 31.37 32.98 34.37 36.44 35.38 37.17 38.70 40.25 Book Value per sh c 46.75 338.84 395.02 395.86 393.72 396.67 400.43 406.07 478.05 480.81 483.42 485.67 487.78 489.40 491.05 491.71 492.01 493.50 495.00 Common Shs Outst'g 0 516.00 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 15.8 15.2 19.3 Botdfig res are AvgAnn'I PIE Ratio 14.5
.69 .61 .66 .73 .70 .87 .79 .67 .85 .75 .88 .81 .84 .80 .80 .96 Vatue Une Relative P/E Ratio .80 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% 3.8% 3.5% 3.4% estin ates Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUCTURE as of 12/31/17 14440 13489 14427 15116 14945 15357 17020 16453 16380 15425 15100 15500 Revenues ($mill) 17000 Total Debt $22812 mill. Due in 5 Yrs $9694 mill. 1208.0 1365.0 1248.0 1513.0 1443.0 1549.0 1634.0 1763.4 2073.6 1783.2 1870 1960 Net Profit ($mill) 2490 LT Debt $19420 mill. LT Interest $874 mill. 31.3% 29.7% 34.8% 31.7% 33.9% 36.2% 37.8% 35.1% 26.8% 33.7% 23.0% 23.0% Income Tax Rate 23.0%
Incl. $1410.5 mill. securitized bonds. Incl. $294 8.0% 8.0% 11.0% 10.0% AFUDC %to Net Profit . 6.0%
mill. capitalized leases. 9.9% 10.9% 10.4% 10.6% 11.2% 7.3% 9.0% 11.0%
(LT interest earned: 3.8x) 59.1% 54.4% 53.1% 50.7% 50.6% 51.1% 49.0% 49.8% 50.0% 51.5% 52.5% 54.5% Long-Term Debt Ratio 50.5%
Leases, Uncapitalized Annual rentals $245.9 mill. 40.7% 45.4% 46.7% 49.3% 49.4% 48.9% 51.0% 50.2% 50.0% 48.5% 47.5% 45.5% Common Equity Ratio 49.5%
Pension Assets-12/17 $5174.1 mill. 26290 28958 29184 29747 30823 32913 33001 35633 34775 37707 40325 43775 Total Capital ($mill) 48800 Oblig $5215.8 mill. 32987 34344 35674 36971 38763 40997 44117 46133 45639 50262 54250 58450 Net Plant ($mill) 68700 Pfd Stock None 6.5%
6.2% 6.2% 5.7% 6.6% 6.1% 6.0% 6.3% 6.1% 7.2% 5.9% 6.0% 6.0% Return on Total Cap'I Common Stock 492,005,598 shs. 11.2% 10.3% 9.1% 10.3% 9.5% 9.6% 9.7% 9.9% 11.9% 9.8% 10.0% 10.0% Return on Shr. Equity 10.5%
11.3% 10.4% 9.1% 10.3% 9.5% 9.6% 9.7% 9.9% 11.9% 9.8% 10.0% 10.0% Return on Com Equity E 10.5%
MARKET CAP: $32 billion (Large Cap) 5.1% 4.6% 3.1% 4.2% 3.5% 3.7% 3.8% 3.9% 5.5% 3.2% 3.5% 3.5% Retained to Com Eq 4.0%
ELECTRIC OPERATING STATISTICS 55% 56% 66% 60% 63% 62% 61% 60% 54% 67% 66% 66% All Div'ds to Net Prof 63%
. 2015 2016 2~1~ r---B-U-SI-N~ES_S_:-Am~e-r-ica-n~E-le-ci-ric~P-o-w-er~C-om_p_a-ny~,-l-n-c.~(A_E_P-),~P-ip_e_lin-e~'0-5;-co~m-m-e-rc-ia~l-b-a-rg-e~op-e-ra-tio-n-in-'1-5-.-G-e~n-er-at-in-g-r
%Change Retail Sales (K'Ml) -1.2 +.3 Avg. Indus!. Use (MWH) NA NA NA . through 10 operating utilities, serves 5.4 mill. customers in Arkan- sources not available. Fuel costs: 34% of revenues. '17 reported Avg. Indus!. Revs._P.er i(WH (¢) NA NA NA sas, Kentucky, Indiana, Louisiana, Michigan, Ohio, Oklahoma, Ten- depreciation rates (utility): 1.6%-9.2%. Has 17,700 employees.
Capacity at Peak (MW) NA NA ~~ nessee, Texas, Virginia, & West Virginia. Electric revenue break- Chairman, President & CEO: Nicholas K. Akins. Incorporated: New Peakload(MII) NA NA NA down: residential, 40%; commercial, 23%; industrial, 19%; whole- York. Address: 1 Riverside Plaza, Columbus, Ohio 4321.5-2373.
Annual load Factor(%) NA NA
%Change Cuslomers (yr-end) +.3 NA NA sale, 15%; other, 3%. Sold SEEBOARD (British utility) '02; Houston Telephone: 614-716-1000. Internet: www.aep.com.
r-------------------------------------------1 F~edChargeCov.(%) 356 374 354 Am.erican Electric Power's earnings billion and would be corppleted by the will likely advance solidly in 2018 and fourth quarter of 2020. This needs the ap-ANNUAL RATES Past Past Est'd '15-'17 proval of the state commissions in Oklaho-of change (per sh) 10 Yrs. 5 Yrs. to '21-'23 2019. The company's utilities are bene-Revenues 1.5% Nil fiting from rate relief. Public Service of ma, Arkansas, ,Texas, and Louisiana. (Op-
"Cash Flow 2.5% 4.0% 2.5% Oklahoma received an $84 million rate in- position to the project has emerged in Ok-Earnings 3.0% 5.5% 4.5%
crease (before passing through to custom- lahoma.) Rulings on the proposals are ex-Dividends 4.0% 4.5% 5.0%
Book Value 4.0% 4.0% 4.5% ers the reduction in federal taxes), based pected by the end of April.
Cal- QUARTERLYREVENUES1$mill.) Full on a 9.3% return on equity. Also this quar- AEP no longer has exposure to the endar Mar.31 Jun.30. Sep.30 Dec.31 Year ter, SWEPCo was granted a hike of $50 vagaries of the power markets. The 2015 million, based on a 9.6% ROE. Indiana & company has sold or written off its non-4580 3827 4431 3615 16453 (This 2016 4045 3893 4652 3790 16380 Michigan has rate cases pending in each regulated generating facilities.
2017 3933 3577 4105 3810 15425 state. In Indiana, the utility reached a caused a large nonrecurring charge in 2018 3850 3450 4100 3700 15100 settlement (subject to approval by the 2016.) It is still seeking a buyer for its 2019 4000 3650 4200 3650 15500 state commission) for an increase of $97 remaining generating assets.
Cal- EARNINGSPERSHAREA Full million, based on a 9.95% ROE. New tar- Finances are solid. The fixed-charge cov, endar Mar.31 Jun.30 Sep.30 Dec.31 Year iffs would take effect in mid-2018. In erage, common-equity ratio, and earned
=
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9 Mh.1k*chigban, dl&M re q u ~~teRdOEa $A52 mdillio? RhOEt a(re heatlthyt. dA)EP's exith from merd-2016 1.02 1.03 1.43 .76 4.23 1 e, ase on a 10 .6 ,o . n or er 1s c an uncon rac e power as 1owere 2017 .94 .76 1.11 .81 3.62 expected in April. Heavy investment in its business risk, too. The company's Fi-2018 1.10 .80 1.25 .75 3.90 electric transmission (some $3 billion an- nancial Strength rating is A+.
2019 1.15 .85 1.30 .80 4.10 nually) is also expanding the company's The stock has a dividend yield that is r--C-al---r--Q-UA-R-TE-R-LY_D_IV_ID-EN_D_S_PA-ID-B-.--11--F-ul-l earning power. Our 2018 and 2019 share- somewhat above the utility average.
endar Mar.31 Jun.30 Seo.30 Dec.31 Year earnings estimates are within AEP's tar- This might well appeal to conservative in-t--20-1-4-+"="-'--==-==-=-..c=='- 1--~ geted ranges of $3.75-$3.95 and $4.00- vestors, given the stock's Safety rank of 1 2*03
.5o .5o .5o *53
~m 2017
- ~~
.59
- ~~
.59
- ~i
.59
- ~~
.62
~:i~
2.39
$4.20, respectively.
The company wants to build a large wind project to serve four states. The (Highest). Total return potential to 2021-2023 does not stand out among electric companies, however.
2018 .62 2,000-megawatt facility would cost $4.5 Paul E. Debbas, CFA March 16, 2018 (A) Dil. EPS. Exel. nonrec. gains (losses): '03, (32¢); '04, 15¢; '05, 7¢; '06, 2¢; '08, 3¢; '15,
- Div'd reinv. plan avail. (C) Incl. intang. In '17: Company's Financial Strength A+
($1.92); '04, 24¢; '05, (62¢); '06, (20¢); '07, 58¢; '16, (1¢). '15-'16 EPS don't sum due to $12.59/sh. (D) In mill. (E) Rate base: various. Stock's Price Stability 95 (20¢); '08, 40¢; '10, (7¢); '11, 89¢; '12, (38¢); rounding. Next egs. report due late April. Rates all'd on com. eq.: 9.65%-10.9%; earn. on Price Growth Persistence 50
'13, (14¢); '16, ($2.99); '17, 26¢; disc. ops.: '03, (B) Div'ds paid early Mar., June, Sept., & Dec. avg. com. eq., '17: 10.0%. Regul. Climate: Avg. Earnings Predictability 85
© 2018 Value Line. Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wtthout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part *11-.,111*~*"1 ' , ll*l!tHl!ll'lll!Hl!al ol rr may be reproduced, resold, stored or transmitted in any printed, electronic or olher form, or used for generaling or marketing any printed or electronic publication, service or product.
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TIMELINESS 3 NYSE-ALE Lowered 1126118 High: 51.3 49.0 35.3 PRICE 37.9 42.5
, RATIO , RE_LAT~IVE_1_1!_D1V' 42.7 54.1 Median:
58.0 16.0 59.7 P/E RATIO ,
66.9 81.2 YLD 74.4
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- IU.,1f!.....1,il_"_"+--1-*--_--::..:-:..:i=-=--+--+---+-- 48 Ann'I Total ,, .... "' *1p1,; 111, 111. l - - , 1 .. 1" "
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THIS STOCK VLARJTH."
INDEX I-to Buy 140 118 117 shares 10 -,,-1r ,.,i....-,-_,--1-,-1:ltttlhmt.
1111
'" ,, 111111 ~ 1 yr. 4.5 10.1 m:.::\001 43j~~. 44J¥1 387~~ traded 5
lllllll111111lllllil 1111i11IIIIl111Il11i1111111111IIIII 111IIIIIllIIIIIIilllIIIIIIIII II ~~:: ~~:~ ~g f-'2=',02'0'='2',--2~0""0'=3-r-=-20,;::;o;..;4~2:;:.oo,;:;5;+,,2..,,.00""'6,...,...,,2"'"0=07~200a 2009 2010 2011 2012 2013 2014 2015 2016 2~01\!!:7~2c:'07:18=+::2=0..,..19=+-.....,;©'""V""'~L"'"'UE:-,L-:,:IN=Ep=u=-s.""'LL"'"c,-,/-,-1.=23=-'
.. .. 25.30 24.50 25.23 27.33 24.57 21.57 25.34 24.75 24.40 24.60 24.77 30.27 27.01 27.78 28.45 28.85 Revenues per sh 30.75
.. .. 2.97 3.85 4.14 4.42 4.23 3.57 4.35 4.91 5.01 5.35 5.68 6.79 7.08 6.59 7.00 7.35 "Cash Flow" per sh 8.50
.. .. 1.35 2.48 2.77 3.08 2.82 1.89 2.19 2.65 2.58 2.63 2.90 3.38 3.14 3.13 3.40
- 3.60 Earnings per sh A 4.25
.. .. .30 1.25 1.45 1.64 1.72 1.76 1.76 1.78 1.84 1.90 1.96 2.02 2.08 2.14 2.24 2.34 Div'd Decl'd per sh 9
- t 2.70
.. .. 2.12 1.95 3.37 6.82 9.24 9.05 6.95 6.38 10.30 7.93 12.48 5.84 5.35 4.08 6.25 6.80 Cap'I Spending per sh 6.25
.. .. 21.23 20.03 21.90 24.11 25.37 26.41 27.26 28.78 30.48 32.44 35.06 37.07 38.17 40.47 42.10 43.80 Book Value per sh c 49.25
.. .. 29.70 30.10 .. 30.40 30.80 32.60 35.20 35.80 37.50 39.40 41.40 45.90 49.10 49.60 51.10 52.00 53.00 Common Shs Outst'g o 56.00
.. .. 25.2 17.9 16.5 14.8 13.9 16.1 16.0 14.7 15.9 18.6 17.2 15.1 18.6 23.0 Bold figl*res are Avg Ann'I P/E Ratio 15.0
-- .. 1.33 .95 .89 .79 .84 1.07 1.02 .92 1.01 1.05 .91 .76 .98 1.14 Value Line Relative PIE Ratio .85
- *- .9% 2.8% 3.2% 3.6% 4.4% 5.8% 5.0% 4.6% 4.5% 3.9% 3.9% 4.0% 3.6% 3.0% estln ates Avg Ann'I Div'd Yield 4.2%
CAPITAL SlRUCTURE as of 12/31/17 801.0 759.1 907.0 928.2 961.2 1018.4 1136.8 1486.4 1339.7 1419.3 1480 1530 Revenues ($mill) 1725 Total Debt $1503.3 mill. Due in 5 Yrs $450.5 mill. 82.5 61.0 75.3 93.8 97.1 104.7 124.8 163.4 155.3 159.2 175 190 Net Profit ($mill) 235 LT Debt $1439.2 mill. LTlnterest $61.9 mill.
(LT interest earned: 3.Bx) 34.3% 33.7% 37.2% 27.6% 28.1% 21.5% 22.6% 19.4% 11.3% 14.8% NMF Nil Income Tax Rate Nil 5.8% 12.8% 8.9% 2.7% 5.3% 4.4% 6.3% 2.0% 1.4% .8% 2.0% 2.0% AFUDC %to Net Profit 1.0%
Leases, Uncapitalized Annual rentals $14.2 mill. 41.6% 42.8% 44.2% 44.3% 43.7% 44.6% 44.2% 46.3% 42.0% 41.0% 40.5% 38.5% Long-Tenn Debt Ratio 38.0%
58.4% 57.2% 55.8% 55.7% 56.3% 55.4% 55.8% 53.7% 58.0% 59.0% 59.5% 61.5% Common Equitv Ratio 62.0%
Pension Assets-12/17 $628.2 mill. 1415.4 1625.3 1747.6 1937.2 2134.6 2425.9 2882.2 3388.9 3263.4 3507.4 3685 3785 Total Capital ($mill) 4450 Oblig $793.2 mill. 1387.3 1622.7 1805.6 1982.7 2347.6 Pfd Stock None 2576.5 3286.4 3669.1 3741.2 3822.4 3960 4120 Net Plant ($mill) 4275 6.7% 4.8% 5.4% 6.0% 5.6% 5.3% 5.2% 5.8% 5.8% 5.5% 5.5% 6. 0% Return on Total Cap'I 6.0%
Common Stock 51,143,656 shs. 10.0% 6.6% 7.7% 8.7% 8.1% 7.8% 7.8% 9.0% 8.2% 7.7% 8.0% 8.0% Return on Shr. Equity 8.5%
as of 2/1/18 10.0% 6.6% 7.7% 8.7% 8.1% 7.8% 7.8% 9.0% 8.2% 7.7% 8.0% 8.0% Return on Com Equity E 8.5%
MARKET CAP: $3.4 billion (Mid Cap) 3.9% .5% 1.5% 2.9% 2.3% 2.2% 2.5% 3.6% 2.8% 2.4% 3.0% 3.0% Retained to Com Eq 3.0%
ELECTRIC OPERATING STATISTICS 61% 93% 81% 66% 71% 72% 67% 60% 66% 68% 66% 65% All Div'ds to Net Prof 64%
%Change Relail Sales (KWH) 2~s~~ 2~21 g fa 2 1.~ f--8-:-:U-SI_N.,_ES_S_:_A_L.,_LE_T_E_,-ln.... c.-is-t-he-'-pa-re-n..,.t-of.1.M-in-n-es_o.1.ta_P_o_w-er.1.,-w-hi-ch-'-p-r-oj-ec-ts.1..-Ac-q-'d_U.1..s___W_a_te.1.r_S-erv_i_ce.,_s_2_/1-5-.H-a-s-re_a_l-es-ta-te-o-'-p-e-ra-tio-n-l Avg.lndu&.Use(MWH) NA NA NA supplies electricity to 146,000 customers in northeastern MN, & Su- in FL. Generating sources: coal & lignite, 41%; wind, 12%; other, Avg.lndu&.Revs.:l(\Ml(j) 6.40 NA NA perior Water, Light & Power in northwestern WI. Electric rev. break- 6%; purchased, 41%. Fuel costs: 28% of revs. '17 deprec. rate:
~:ff1~a~'.~;M~l 1942 NA NA down: !aconite mining/processing, 26%; paper/wood products, 9%; 3.2%. Has 2,000 employees. Chairman, President & CEO:.Alan R.
Annual load Factor(%
16 Jl_ JR 15 15 Jl other industrial, 8%; residential, 12%; commercial, 13%; wholesale, Hodnik. Inc.: MN. Address: 30 West Superior St., Duluth, MN
%ChangeCustomera
_ ____ _ _ _ _NA avg.) ___ NA_ _NA _ f-_ 16% _other,
_ _16%. __ ALLETE
_ _Clean _ _Energy _..;;.:__owns _ renewable
____ energy
....::.;_ 55802-2093.
_ _ _ _Tel.: __ 218-279-5000.
____ Internet:
_ _www.allete.com.
_ _ _ _ _ _ _-l F~ed Charge Cov. (%) 381 318 339 ALLETE 1s main utility subsidiary re- is within ALLETE's targeted range of ANNUAL RATES Past Past Est'd '15-'17 ceived a disappointing rate decision. $3.20-$3.50. Note that the company's prof-of change (per sh) 10 Yrs. 5Yrs. to '21-'23 Minnesota Power had sought a rate in- its in the fourth quarter of 2017 benefited Revenues 1.0% 2.5% 1.5% crease of $55 million (8.6%), based on a from the revaluation of deferred taxes due "Cash Flow" 5.0% 7.5% 3.5% 10.25% return on a 53.8% common-equity to the new federal tax law. This added Earnings 1.5% 5.5% 4.5%
Dividends 3.5% 3.0% 4.5% ratio. The state commission (through a $0.25 a share to the bottom line, which we Book Value 6.0% 6.0% 4.0% verbal order) granted a hike of $13 million excluded as a nonrecurring item.
Cal- QUARTERLY REVENUES ($ mill.) Full (2.0%), based on a 9.25% return on the We forecast solid profit growth next endar Mar.31 Jun. 30 Sep. 30 Dec. 31 Year same common-equity ratio. Minnesota year. The factors that are likely *to help 2015 320.0 323.3 462.5 380.6 1486.4 Power expected to r:eceive a written order earnings in 2018 should
- be present in 2016 333.8 314.8 349.6 341.5 1339.7 shortly after our report went to press, and 2019, as well. We look for a 6% increase in 2017 365.6 353.3 362.5 337.9 1419.3 plans to decide what steps it will take once share net, which is within ALLETE's an-2018 370 360 390 360 1480 management reviews the order. nual growth goal of 5%-7%.
2019 380 375 400 375 1530 We think earnings will advance solid- The board of directors raised the divi-Cal- EARNINGS PER SHARE A Full ly in 2018. Minnesota Power should dend in the first quarter. The annual endar Mar.31 Jun. 30 Sep. 30 Dec. 31 Year benefit from healthy industrial demand for increase was $0.10 a share (4.7%), a 2015 .85 .46 1.23 .83 *3.38 power. The utility is also earning a return greater hike than in recent years. The ae-2016 .93 .50 .81 .89 3.14 on the construction work in progress for a celerated growth rate is in line with the 2017 .97 .72 .88 .56 3.13 transmission line that is scheduled for company's expectation of faster profit 2018 1.00 .60 .95 .85 3.40 completion in 2020. ALLETE's wind- growth. ALLETE is targeting a payout 2019 1.05 .65 1.00 .90 3.60 energy subsidiary should benefit from in- ratio of 60%-65%.
Cal- QUARTERLY DIVIDENDS PAID 9
- t Full creased production and the construction This stock's dividend yield is close to endar Mar.31 Jun.30 Seo.30 Dec.31 Year and sale of a SO-megawatt project to a util- the average for electric utility equi-2014 .49 .49 .49 .49 1.96 ity in North Dakota. U.S. Water Services ties. With the recent quotation above the 2015 .505 .505 .505 .505 2.02 is seeing rising demand for its water- midpoint of our 3- to 5-year Target Price 2016 .52 .52 .52 .52 2.08 treatment services and a full year of reve- Range, total return potential is unappeal-2017 .535 .535 .535 .535 2.14 nues from an acquisition it made last Sep- ing.
2018 .56 tember. Our 2018 share-earnings estimate Paul E. Debbas, CFA March 16, 2018 (A) Diluted EPS. Exel. nonrec. gain (losses): to rounding. Next earnings report due early deferred charges. In '17: $11.95/sh. (D) In mill. Company's Financial Strength A
'04, (25¢); '05, ($1.84); '15, (46¢); '17, 25¢; May. (B) Div'ds historically paid in early Mar., (E) Rate base: Orig. cost depr. Rate allowed in Stock's Price Stability 95 gain (losses) on disc. ops.: '04, $2.57, '05, June, Sept. and Dec.
- Div'd reinvest. plan MN on com. eq. in '1 B: 9.25%; earned on avg. Price Growth Persistence 40 (16¢); '06, (2¢). '15 & '16 EPS don't sum due avail. t Shareholder invest. plan avail. (C) Incl. com. eq., '17: 8.6%. Regulatory Climate: Avg. Earnings Predictability 85
© 2018 Value Line, Inc. All rights reseived. Factual material is obtained Jrom sources believed to be reliable and is provided wnhout warranties of any kind.
TH_E PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRO_RS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal. use. No part To subscribe call 1-800-VALUELINE of It may be reproduced, resold, stored or transmitted 1n any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, seiv1ce or product.
18-WSEE-328-RTS I--DJJ_Kf_e~~R_G_y NYSE-DUK
~--,-------,---,-----Jl.__,_REC_ENT_l PRICE 4_4j--'--P/E_J!!(_Tra-iling_:
, RATIO , Median: 17.0 P/E RATIO !!~D-IV'D-~~90_11 19_.1)-1---RE-LATIV-E , YLD /(0 lf,w*1_----.
TIMELINESS 4 LoweredG/23117 High: 63.9 61.81 53.8 55.8 46.4 66.4 50.6 71.1 59.6 75.5 64.2 87.3 67.1 90.0 65.5 87.8 70.2 91.8 76.1 84.4 72.9 Target Price Range 2021 2022 2023
>---"'L=ow~:~_5_0~.7~~40~.5~_,35.2 SAFETY 2 New 6/1/07 LEGENDS TECHNICAL 1 Raised 12/22/17 - ~~:d~vi1~t~~:sf ~~te
. . . . Relative ~rice Strength 11 l - - + - - - - f - - - + - - '-"'"n..,..,"l'---+--+---+--+---+
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.. --+---+--+---+--+ 160 120 BETA .60 (1.00=Market) 1-for-3 Revspltt 7/12 ~ ----- ****** 100 1--~20=2=1.~2=3=p=Ro=J~E=c=n=o=N=s---1 o~i~~!~~r~a indicates recession .,,..:;... - ~ ... *"' * - - - * * - * * - *
- 80 Price Gain Ann'I Total Return P~T~~r~~~-,-,--::: ;::
.. 111 1
--r~i:ii<i;;~t;:ii11i;:;:;.l~?'Tjj' 111 .. 1f;;,,~11F=,Ti,~~-:,,;.c:f:i.._;:-_~_:-:_j-----j1-f~=-=-=1=.;160 High 110 (+50%) 14% " 1 1
1,,,, ,, * " 1 ... ~ - 'I' 50 Low 85 {+15%) 8% ' 40 1"i"*--** * .**** *.......****** *.
Insider Decisions * "*.:>; .....
- 30 to Buy ~ ~ ~ ~ ~ ~ ~ ~ ~ I i ****** ....... .......:** *.................... ********** 20 Options060000000 I I to Sell o 2 o o 1 o o 1 o 1---+----;t----+-i--t----+- ---1---1----1---1----1 ---1----1-----1 % TOT. RETURN 1118 >- 15 I
Institutional Decisions
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THIS VLARITH."
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~ 1 1Q2D17 2Q2D17 3Q2017 Percent 15 I *' ii+,j+i+,o-,+--+----.---+----.---+----.-----. 1 yr. srg_~K to Buy 552 528 531 shares 10J' loSell 500 509 494 traded 5 fltttttttt:::ttttt,,lttlt,,::,fll;:,,tt::11+* * * +lrrt.,1t1,.11tt,,ttt-,---t---13yr. 2.4 38.0 -
Hld'slDODI 437355 435858 442941 111 1111111111 fil1111111 5 yr. 41.5 85.6 1-:2=0:=0='2.-2=0=0=3-r-:-20=0,...,4....-:'20'="0"=s--2-=-oo=s,..,-,,2=0=01 200a 2009 2010 2011 2012 2013 2014 201s 201s 2"!0'!-'11='""-2:-:0~1a.,..+2=0,...,1-=-9+-,@"""v=AL=u=EL=1N=E=Pu=e.~LL:-:C.,.,,1-,-1-~23-=--'
31.15 29.18 32.22 32.63 27.88 34.84 33.84 34.10 32.49 33.50 33.85 34.80 Revenues per sh 37.75 7.34 7.58 8.49 8.68 6.80 8.56 9.11 9.40 9.20 10.15 10.95 11.40 "Cash Flow" per sh 13.00 3.03 3.39 4.02 4.14 3.71 3.98 4.13 4.10 3.71 4.30 4.80 5.00 Earnings per sh A 5.50 2.70 2.82 2.91 2.97 3.03 3.09 3.15 3.24 3.36 3.49 3.64 3.80 Div'd Decl'd per sh 8
- 4.40 10.35 9.85 10.84 9.80 7.81 7.83 7.62 9.83 11.29 13.45 15.35 15.25 Cap'l Spending per sh 12.75 49.51 49.85 50.84 51.14 58.04 58.54 57.81 57.74 58.62 59.35 60.45 61.60 Book Value per sh c 65.00
- - 423.96 436.29 442.96 445.29 704.00 706.00 707.00 688.00 700.00 701.00 702.00 703.00 Common Shs Outst'g 0 706.00 17.3 13.3 12.7 13.8 17.5 17.4 17.9 18.2 21.3 19.6 Bold fig res are Avg Ann'I P/E Ratio 18.0 1.04 .89 .81 .87 1.11 .98 .94 .92 1.12 .95 Vatue Une Relative PIE Ratio 1.00 estinates 5.2% 6.2% 5.7% 5.2% 4.7% 4.4% 4.3% 4.3% 4.3% 4.2% Avg Ann'I Div'd Yield 4.5%
CAPITAL STRUCTURE as of 9/30/17 13207 12731 14272 14529 19624 24598 23925 23459 22743 23500 23750 24450 Revenues ($mill) 26650 Total Debt $53313 mill. Due in 5 Yrs $18876 mill. 1279.0 1461.0 1765.0 1839.0 2136.0 2813.0 2934.0 2854.0 2560.0 3005 3385 3515 Net Profit ($mill) 3970 LT Debt $48929 mill. LT Interest $1795 mill. 32.5% 34.4% 32.6% 31.3% 30.2% 32.6% 30.6% 32.2% 31.0% 31.5% 20.0% 20.0% Income Tax Rate 20.0%
Incl. $1100 mill. capitalized leases. 11.0%
(LT interest earned: 2.9x) 16.0% 17.5% 22.7% 23.2% 22.3% 8.8% 7.2% 9.2% 11.7% 13.0% 12.0% 12.0% AFUDC %to Net Profit 38.7% 42.6% 44.3% 45.1% 47.0% 48.0% 47.7% 48.6% 52.6% 54.0% 54.5% 55.5% Long-Tenn Debt Ratio 57.0%
Leases, Uncapitalized Annual rentals $218 mill. 61.3% 57.4% 55.7% 54.9% 52.9% 52.0% 52.3% 51.4% 47.4% 46.0% 45.5% 44.5% Common Equity Ratio 43.0%
Pension Assets-12/16 $8531 mill. 34238 37863 40457 41451 77307 79482 78088 77222 86609 90200 93525 96900 Total Capital ($mill) 107000 Oblig $8006 mill. 34036 37950 40344 42661 68558 69490 *70046 75709 82520 87850 94325 100525 Net Plant ($mill) 112900 Pfd Stock None 4.5% 4.5% 4.5% Return on Total Cap'I 5.0%
4.8% 4.9% 5.5% 5.6% 3.6% 4.6% 4.8% 4.8% 4.0%
Common Stock 699,975,614 shs. 6.1% 6.7% 7.8% 8.1% 5.2% 6.8% 7.2% 7.2% 6.2% 7.0% 8.0% 8.0% Return on Shr. Equity 8.5%
6.1% 6.7% 7.8% 8.1% 5.2% 6.8% 7.2% 7.2% 6.2% 7.0% 8.0% 8.0% Return on Com Equity E 8.5%
MARKET CAP: $52 billion (Large Cap) .6% 1.1% 2.1% 2.2% .9% 1.5% 1.7% 1.5% .6% 1.5% 2.0% 2.0% Retained to Com Eq 2.0%
ELECTRIC OPERATING STATISTICS 89% 84% 73% 72% 82% 78% 76% 79% 91% 81% 75% 76% All Div'ds to Net Prof 78%
2014 2015 20~~ 1--B-U-SI-N~E-SS_:_D_u~ke_E_n_e_rg~y-C-or-po-ra~ti-on-1-*s_a.._h_ol-di-ng_c.._o_m_pa_n_y.._fo_r_ut-il---'-r-es-id-e-nt~ia-l,-4-3_%.._;-co_m_m_e...rc-ia-1,-2-9.._%_;-in-du-s-tr-ia-1,-1-4%-,;-o-t-he...r,-1-4_%__-1
%ChangeRetai1Sales(Kl'Af) +2.2 +.6 Avg. lndu~. Use (MWH) 2876 2883 3486 ities with 7.4 mill. elec. customers in NC, FL, IN, SC, Oh, & KY, and Generating sources: coal, 27%; nuclear, 27%; gas, 23%; other, 1%;
Avg. lndu~. Revs1.er KV.1i (¢) 6.15 NA NA 1.5 mill. gas customers in OH, KY, NC, SC, and TN. Owns inde- purchased, 22%. Fuel costs: 30% of revs. '16 reported deprec. rate:
Caparitya!Peak(MW) NA NA NA pendent power plants & has 25% stake in National Methanol in 2.8%. Has 28,800 employees. Chainnan, President & CEO: Lynn J.
Peak load, Summer IMw)
Annual load Factor(%)
NA NA NA NA ~ Saudi Arabia. Acq'd Progress Energy 7/12; Piedmont Natural Gas Good. Inc.: DE. Address: 550 South Tryon St., Charlotte, NC
%ChangeCustomers(avg.) +1.0 +1.2 +1.4 10/16; discontinued most int'I ops. in '16. Elec. rev. breakdown: 28202-1803. Tel.: 704-382-3853. Internet: www.duke-energy.com.
1-------------------------------------------1 f~edChargeCov.(%) 315 317 264 One of Duke Energy's utilities has third-period tally was weakened by unfa-f-A-N_N_U-'A'-L-RA-'-T'-ES--P-as-t--P-as_t_E-st-,d-,-14-_,-16-i reached a partial settlement of its vorable weather conditions, an $0.08-a-ofchange(persh) 10Yrs. svrs. to'21-'23 rate case. Duke Energy Progress filed for share write-off of a nonregulated wind-Revenues 3.0% 1.5% 1.5% an increase of $477 million (14.9%), based farm, and a $0.12-a-share charge for the "Cash Flow" 1.5% 2.5% 5.0% on a 10.75% return on a 53% common- cancelation of a nuclear project that was 35 5f.Ji~i~RJs * .:: 2:~~ :j~ equity ratio. The settlement with the staff under consideration in Florida. Rate relief Book Value -.5% 3.0% 1.5% of the North Carolina Utilities Commis- should be a positive factor for the bottom 1--C-al--~-Q-UA_R_TE_R-LY_R_EV_E-NU-E-S(-$m_i_ll.)~~F-ul~I sion (NCUC) would provide for a hike (be- line each year. All told, we estimate share endar Mar.31 Jun.30 Sep.30 Dec.31 Year fore the pass-through of reduced federal earnings of $4.80 this year and $5.00 in 2015 6065 5599 6483 5322 23459 income taxes) of $127 million (4.0%). based 2019.
2016 5377 5213 6576 5577 22743 on a return of 9.9% on a common-equity Some significant capital projects are 2017 5729 5555 6482 5734 23500 ratio of 52%. The treatment of deferred under way. Duke is building gas-fired 2018 5750 5600 6600 5800 23750 costs associated with storms and coal ash plants in South Carolina and Florida and 2019 5900 5700 6950 5900 24450 basin remediation has not been resolved, modernizing the electric system in Indiana Cal- EARNINGS PER SHARE A Full so far. and the western Carolinas. This will ex-endar Mar.31 Jun.30 Sep.30 Dec.31 Year Other rate cases are pending. Duke pand the company's rate base, and thus,
_87 1.44 _70 4_10 Energy Carolinas asked the NCUC for an its earning power. Duke also intends to ex-2o1 5 1_09 2016 .83 .90 1.44 .53 3.71 inc.rease of $647 million (13.6%), based on pand its gas pipeline infrastructure. The 2017 1.02 .98 1.36 .94 4.30 a 10.75% return on a 53% common-equity company's goal for average annual profit 2018 1.05 1.05 1.65 1.05 4.80 ratio. New tariffs should take effect in the growth is 4%-6%.
2019 1.10 1.10 1.70 1.10 5.00 second quarter. Duke asked the Kentucky This stock is ranked unfavorably for Cal- QUARTERLY DIVIDENDS PAID e. Full commission for a boost of $48. 6 million Timeliness, but offers a dividend yield endar Mar.31 Jun.30 Sec.30 Dec.31 Year (15%), based on a 10.3% return on a 49% that is well above the utility average.
2014 _ common-equity ratio. New rates are likely The yield is about a percentage point 78 78 795 795 3 15 20 15 :795 :795 :825 :825 3_24 two take te.ffecttin Aprilh. . . above the norm for thhis industry. Total red-2016 .825 .825 .855 .855 3.36 e es rma e a s arp earm.ngs 1n- turn potentia1 over t e 3 - to 5 -year perio 2017 .855 .855 .89 .89 3.49 crease in 2018, followed by a more is attractive.
2018 moderate rise in 2019. Last year, the Paul E. Debbas, CFA February 16, 2018
{A) Dil. EPS. Exel. nonrec. losses: '12, 70¢; report due early May. (B) Div'ds paid mid-Mar., Rates all'd on com. eq. in '13 in NC: 10.2%; in Company's Financial Strength A
'13, 24¢; '14, 67¢; gains (losses) on disc. ops.: June, Sept., & Dec.* Div'd reinv. plan avail. '17 in SC: 10.1%; in '09 in OH: 10.63%; in '04 Stock's Price Stability 100
'12, 6¢; '13, 2¢; '14, (80¢); '15, 5¢; '16, (60¢). (C) Incl. intang. In '16: $46.17/sh. (D) In mill., in IN: 10.3%; earn. on avg. com. eq., '16: 6.3%. Price Growth Persistence 40
'16 EPS don't sum due to rounding. Next egs. adj. for rev. split. (E) Rate base: Net orig. cost. Reg. Clim.: NC Avg.; SC, OH, IN Above Avg. Earnings Predictability 85
© 2018 Value Line, Inc. All rights reseived. Factual material is obtained 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 subscriber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of tt may be reproduced, resold, stored or t1ansmttted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
18-WSEE-328-RTS CON. EDISON NYSE-ED IRECENT PRICE 75 ,88 IP/ERATIO 17, acrailing:19.2)
Median: 15.0 RElATIVE PIE RATIO O93 DIV'YLDD 3.8%
I
- fl!1*11 TIMELINESS 4 Lowered 8/18117 High: 52.9 49.3 46.3 51.0 62.7 66.0 64.0 68.9 72.3 81.9 89.7 84.9 Target Price Range Low: 43.1 34.1 32.6 41.5 48.6 53,6 54.2 52.2 56.9 63.5 72.1 74.6 2021 2022 2023 SAFETY 1 New 7/27/90 LEGENDS 120 2 - ~:~ ~vi1i1~~!sf ~~le 100 TECHNICAL Lowered 2/9/18 . , . , Relative ~rice Strength ,,. - - , ** 11 ...... - ., 80 BETA .50 (1 .00 = Market)
., illl 11111 .....
- - .... 1..*
O~~~~!/ir~a indicates recession ~
. . . . . . 111 64 "b 11"1111.11, 1111111'1 2021-23 PROJECTIONS -4 48 Ann'I Total 1,1*** '
- ~1 M* 11*1~1 *1* * ***11 High Price Gain 85 (+10%l Return 7% . ****** -:**1 ....... 1*..,* *....*****. ....
... ... -- ... 32 Low 70 Insider Decisions
(-10% 2%
I I 24 20 AMJJASOND I I 16 toBuy 11 9 811 8 811 8 8 I l 12 Options 392000220 to Soll 0 0 0 0 1 0 ~ 0 0 Institutional Decisions I I %TOT. RETURN 1/18 t-8 I I I THIS VLARITH.'
1Q2017 2Q2017 3Q2017 Percent 21 STOCK INDEX
,I to Buy 322 330 335 II. ., I. 1 yr. 11.8 17.3 I-tMil shares 3yr. 29.7 38.0 t-to Soll 336 323 322 traded 1 7 4- " ,1 ~
Hld'slOOOI 197947 196270 197384 1111 ;111111111 fu111iiii 1111111111 filtl,11111111111111111 Syr. 72.1 85.6 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 © VALUE LINE PUB. LLC 1, 1-23 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 42.85 39.59 37.60 38.80 39.80 Revenues per sh 43.00 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 7.93 7.89 8.40 8.80 9.15 "Cash Flow" per sh 10.50 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 4.05 3.94 4.05 4.20 4.30 Earnings per sh A 4.75 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 2.76 2.86 2.96 Div'd Decl'd per sh e
- 3.30 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 10.42 12.07 11.90 12.45 11.40 Cap'I Spending per sh 11.50 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 44.55 46.88 48.65 50.15 51.65 Book Value per sh c 56.50 213.93 225.84 242.51 245.29 257.46 272.02 273.72 281.12 291.62 292.89 292.87 292.87 292.88 293.00 305.00 311.00 312.00 313.00 Common Shs Outst'g o 316.00 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 15.6 18.B 20.0 Bold fig res are Avg Ann'I P/E Ratio 16.5
.73 .82 .96 .BO .84 .73 .74 .83 .85 .95 .98 .83 .84 .79 .99 1.00 Value Une Relative P/E Ratio .90 estln ates 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% 4.1% 3.6% 3.4% Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUCTURE as of 9/30/17 13583 13032 13325 12938 12188 12381 12919 12554 12075 11700 12100 12450 Revenues ($mill) 13600 Total Debt $15694 mill. .Due In 5 Yrs $3585 mill. 933.0 868.0 992.0 1062.0 1141.0 1157.0 1066.0 1193.0 1189.0 1265 1320 1320 Net Profit ($mill) 1550 LTDebt$14651 mill. LT Interest $667 mill.
(LT interest earned: 3.5x) 36.0% 34.2% 36.0% 36.1% 34.5% 31.8% 34.0% 33.6% 35.3% 36.0% 23.0% 23.0% Income Tax Rate 23.0%
1.7% 2.6% 2.4% 1.6% .5% .5% .3% .7% 1.3% 1.0% 1.0% 1.0% AFUDC %to Net Profit 1.0%
Leases, Uncapitalized Annual rentals $61 mill. 48.3% 48.5% 48.6% 46.5% 45.9% 46.1% 48.0% 47.9% 50.8% 50.0% 50.5% 49.5% Long-Tenn Debt Ratio 48.0%
50.6% 50.4% 50.4% 52.5% 54.1% 53.9% 52.0% 52.1% 49.2% 50.0% 49.5% 50.5% Common Equity Ratio 52.0%
Pension Assets-12/16 $12472 mill. 19160 20330 21952 21794 21933 22735 24207 25058 29033 30175 31600 31950 Total Capital ($mill) 34400 Oblig $14095 mill. 23863 Pfd Stock None 20874 22464 25093 26939 28436 29827 32209 35216 37550 40025 42075 Net Plant ($mill) 47900 6.2% 5.7% 5.9% 6.2% 6.5% 6.4% 5.6% 6.0% 5.3% 5.5% 5.5% 5.5% Return on Total Cap'I 5.5%
Common Stock 310,068,797 shs. 9.4% 8.3% 8.8% 9.1% 9.6% 9.4% 8.5% 9.1% 8.3% 8.5% 8.5% 8.5% Return on Shr. Equity 8.5%
as of 10/31/17 9.5% 8.4% 8.9% 9.2% 9.6% 9.4% 8.5% 9.1% 8.3% 8.5% 8.5% 8.5% Return on Com Equity E 8.5%
MARKET CAP: $24 billion (Large Cap) 3.1% 2.5% 3.2% 3.1% 3.6% 3.6% 2.6% 3.5% 3.0% 2.5% 3.0% 3.0% Retained to Com Eq 3.0%
ELECTRIC OPERATING STATISTICS 67% 71% 65% 66% 62% 62% 69% 61% 64% 67% 67% 67% All Div'ds to Net Prof 67%
2014 2015 2016 BUSINESS: Consolidated Edison, Inc. is a holding company for
%Cha~e Relail Sales (KWH) -1.1 +1.9 . .4 opportunities through three wholly owned subsidiaries. Entered into Avg. In ust. Use (MWH~ NA NA NA Consolidated Edison Company of New York, Inc. (CECONY), which midstream gas joint venture 6/16. Purchases most of its power.
Avg. lndusl. Revsi (¢) NA NA NA sells electricity, gas, and steam in most of New York City and Fuel costs: 26% of revenues. '16 reported depreciation rates: 2.9%-
Capacity al Peak ~ NMF NMF NA Westchester County. Also owns Orange and Rockland Utilities 3.1 %. Has 15,000 employees. Chairman, President & CEO: John Peak load, Summer ) 13568 13721 NA Annual load Factor ( 'I
%Change Customers yr-en~
NMF NMF NA NA NMF NA (O&R), which operates in New York and New Jersey. Has 3.6 mil-lion electric, 1.2 million gas customers. Pursues competitive energy McAvoy. Inc.: New York. Address: 4 Irving Place, New York, New York 10003. Tel.: 2124604600. Internet: www.conedison.com.
F~ed Charge Gov.(%) 366 370 352 We estimate that Consolidated growth in recent years. ConEd's goal is a ANNUAL RATES Past Past Est'd '14-'16 Edison's earnings will advance mod- payout ratio in a range of 60%-70%.
of change (per sh) 10Yrs. 5Yrs. to '20-'22 estly in 2018 and 2019. The company's Finances are strong. The fixed-charge Revenues -.5% -1.5% .5% primary utility subsidiary, Consolidated coverage and common-equity ratios are "Cash Flow" 4.5% 4.5% 4.5% Edison Company of New York, will benefit solid. The latter figure was augmented by Earnings 3.5% 2.5% 3.0%
Dividends 1.5% 2.0% 3.5% from rate increases each year. Electric and the sale of 4.1 million common shares last Book Value 4.0% 3.5% 3.5% rs hikes of $155.3 million (2.0%) and August. Earned returns on equity are not QUARTERLY REVENUES ($ mill.) 92.3 million (5.6%), respectively, took ef- exceptionally high, but have been relative-Cal- Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year feet at the start of 2018. Electric and gas ly consistent in recent years as the utili-2015 3616 2788 3443 2707 12554 increases of $155.2 million (1.9%) and ties have earned (or have come close to 2016 3157 2794 3417 2707 12075 $89.4 million (5.1 %) will go into effect at earning) their allowed. returns on equity.
2017 3228 2633 3211 2628 11700 the start of 2019. In addition, the compa- The company merits a Financial Strength 2018 3300 2750 3300 2750 12100 ny's utilities continue to see customer con- ratio~ of A+, our second highest.
2019 3400 2825 3400 2825 12450 versions from oil heat to gas heat. And The mstallation of smart meters is un-Cal- EARNINGS PER SHARE A Full ConEd's clean energy (solar and wind) der way. The $1.4 billion investment is endar Mar.31 Jun.30 Sep.30 Dec.31 Year businesses are boosting their income by scheduled for completion by 2022, with the 2015 1.26 .74 1.45 .60 4.05 adding projects. Finally, ConEd has a peak spending set to occur two years from 2016 1.05 .77 1.47 .64 3.94 12.5% stake* in a gas pipeline that is now. All told, 5.4 million smart meters will 2017 1.27 .57 1.48 .73 4.05 scheduled for an in-service date in late be installed in New York City and West-2018 1.30 .63 1.60 .67 4.20 2018. This represents a $400 million in- chester.
2019 1.30 .65 1.65 .70 4.30 vestment for the company. This top-quality stock is ranked unfa-Cat-* QUARTERLY DIVIDENDS PAID e
- Full The board of directors raised the divi- vorably for Timeliness. The dividend endar Mar.31 Jun.30 Sen.30 Dec.31 Year dend in the first quarter of 2018. This yield is about average for a utility. Like 2014 .63 .63 .63 .63 2.52 is the usual timing of the annual increase. most utility equities, the recent quotation 2015 .65 .65 .65 .65 2.60 The board boosted the yearly disburse- is within our 2021-2023 Target Price 2016 .67 .67 .67 .67 2.68 ment by $0.10 a share (3.6%). This was the Range. Accordingly, total return potential 2017 .69 .69 .69 .69 2.76 largest increase in a long time and contin- is unspectacular.
2018 .715 ued a pattern of accelerating dividend Paul E. Debbas, CFA February 16, 2018 (A) Diluted EPS. Exel. nonrec. gains (losses): N_ext earnings_ report ~ue early May. (BJ Div'ds base: net orig. cost. Rate allowed on com. eq .. Company's Financial Strength A+
'02, (11¢); '03, (45¢); '13, (32¢); '14, 9¢; '16, historically paid 1n mid-Mar., June, Sept., and for CECONY in '17: 9.0%; O&R in '15: 9.0%; Stock's Price Stability 95 15¢; gain on discontinued operations: '08, Dec.
- Div'd reinvestment plan avail. (C) Incl. earned on avg. com. eq., '16: 8.6%. Regulatory Price Growth Persistence 40
$1.01. '16 EPS don't sum due to rounding. intang. In '16: $25.29/sh. (D) In mill. (E) Rate Climate: Below Average. Earnings Predictability 95
© 2018 Value Lme, Inc. All rights reserved. Factual matenal is obtained from sources believed to be reliable and is provided wnhout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of nmay be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
18-WSEE-328-RTS i--E_L_PA_S-=--O_E_L_EC_T.--R_IC--,--N_YS-.E-E_E---,--~1~--~rJE_NT--,--5_0.-.25~1~----,/ETI0_2_0*.--4(_i~~--,--l/~~;_m_H_rELARA----,Tr1t_1_.0-r--'9-~-r-D _2__,..9°_Yoliitl_-----i TIMELINESS 3 Loweredl/26118 High: 28.2 25.5 21.1 28.7 35.7 35.3 39.1 42.2 41.3 48.8 61.2 55.8 Target Price Range Aaised5/11/07 i-=~'-=~-'-'~'-~N....D~S=-20"-'.=-8.L---"15=-'.2=--.,_-i11.6 18.7 26.7 29.2 31.8 33.4 33.8 37.2 44.7 48.1 2021 2022 2023 SAFETY 2 TECHNICAL 3 Lowered 4/6/18 - ~ii~:d ~vi1~t~1:sr ~~te
, , , , Relative ~rice Strength BO 60 75 0 BETA
- 2021*23 (l.OO = Market)
PROJECTIONS j~~~~/i;,a indicates recession t--+----+---+--=--+--+----+-=-'1' /--.. ~---
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=
l-='Hld:,.::'s,c.;IIOO;,:.<D,....,;c45:,.::0,;:..99:....,..4-"5="1,;:..23:....,...;;39:,.::6...:.40:c+~~~~-,1,11,J.u 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUELINEPUB.LLC 1.23 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 21.01 21.89 22.59 22.80 23.35 Revenues per sh 25.00 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 5.75 5.98 6.17 6.35 6.60 "Cash Flow" per sh 7.50
.57 .64 .69 .76 1.27 1.63 1.73 1.50 2.07 2.48 2.26 2.20 2.27 2.03 2.39 2.42 2.45 2.60 Earnings per sh A 3.00
-- -* .. *- -- -- .. -- -- .66 .97 1.05 1.11 1.17 1.23 1.32 1.42 1.52 Div'd Decl'd per sh B 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 8.55 7.03 5.91 6.80 6.85 Cap'I Spending per sh 7.25 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 25.13 26.52 28.14 29.20 30.25 Book Value per sh c 33.50 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 40.44 40.52 40.58 40.60 40.70 Common Shs Outst'g o 41.00 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 18.3 18.7 21.8 Bold fig res are Avg Ann'l P/E Ratio 17.0
.81 .72 .79 .92 .89 .86 .92 .98 1.10 Value Line Relative P/E Ratio .95 1.26 1.04 1.16 1.42 .91 .72 .68 estin ates
-- -- .. *- -- -- .. *- -- 2.1% 3.0% 3.0% 3.0% 3.1% 2.7% 2.5% Avg Ann'I Div'd Yield 3.5%
CAPITAL STRUCTIJRE as of 12/31/17 1038.9 828.0 877.3 918.0 852.9 890.4 917.5 849.9 886.9 916.8 925 950 Revenues ($mill) 1025 Total Debt $1369.5 mill. Due in 5 Yrs $218.5 mill. 77.6 66.9 90.3 103.5 90.8 88.6 91.4 81.9 96.8 98.3 100 105 Net Profit ($mill) 125 LT Debt $1196.0 mill. LT Interest $72.3 mill. 32.8% 33.1% 36.1% 34.2% 34.1% 33.0% 31.0% 29.9% 35.8% 34.2% 24.5% 24.5% Income Tax Rate 24.5%
(LT interest earned: 2.9x) 14.0%
20.4% 24.3% 22.1% 17.6% 22.4% 24.1% 30.8% 27.5% 17.6% 11.2% 13.0% 12.0% AFUDC %to Net Profit 53.8% 52.7% 51.2% 51.8% 54.8% 51.4% 53.5% 52.7% 52.7% 51.2% 53.0% 52.0% Long.Tenn Debt Ratio 54.5%
Pension Assets*12/17 $304.4 mill. 46.2% 47.3% 48.8% 48.2% 45.2% 48.6% 46.5% 47.3% 47.3% 48.8% 47.0% 48.0% Common Equity Ratio 45.5%
Oblig $362.0 mill. 1503.9 1527.7 1660.1 1576.7 1824.5 1943.5 2118.4 2150.8 2269.9 2338.2 2530 2575 Total Capital ($mill) 3025 Pfd Stock None 1595.6 1756.0 1865.8 1947.1 2102.3 2257.5 2488.4 2695.5 2821.2 2928.4 3045 3160 Net Plant ($mill) 3550 6.7% 6.0% 7.0% 8.3% 6.5% 6.1% 5.7% 5.3% 5.8% 5.8% 5.5% 5.5% Return on Total Cap'I 6.0%
Common Stock 40,661,003 shs.
as of 1/31/18 11.2% 9.3% 11.1% 13.6% 11.0% 9.4% 9.3% 8.1% 9.0% 8.6% 8.5% 8.5% Return on Shr. Equity 9.0%
11.2% 9.3% 11.1% 13.6% 11.0% 9.4% 9.3% 8.1% 9.0% 8.6% 8.5% 8.5% Return on Com Equity E 9.0%
MARKET CAP: $2.0 billion (Mid Cap) 11.2% 9.3% 11.1% 10.0% 6.3% 4.9% 4.8% 3.4% 4.4% 3.9% 3.5% 3.5% Retained to Com Eq 3.5%
ELECTRIC OPERATING STATISTICS *- -- -- 26% 43% 47% 49% 57% 51% 54% 57% 58% All Div'ds to Net Prof 61%
%Change Retail Sales (KWH) 2015 2016 2
+2.3 +.1
~l ES_S_:_E_ILP-a-so-ELle-cir-ic_CLom_p_a-ny-'-(E_P_E_)_pLro-vi-de_s_eLle-c-tri-c--'-a-bl-e.---'Ge~n-e-ra-tin-g'--so-u-rc-esL:-n-u-cl-eaLr,-4-9-o/c-,;-g-a-s,-3-6-%-;-p-urLch-a-se-d-,~
1--B-US_I_N....
Avg. lndust. Use (MWHI 21687 21036 21553 service to 417,000 customers in an area of approximately 10,000 15%. Fuel costs: 27% of revenues. '17 reported depreciation rate:
Avg. lndust. Revs._P.er KWH (¢) NA NA NA square miles in the Rio Grande valley in western Texas (68% of 2.3%. Has about 1,100 employees. Chairman: Charles A.
Capac~ at Peak (MW) 2055 2080 2082 revenues) and southern New Mexico (19% of revenues), including Yamarone. President & CEO: Mary E. Kipp. Incorporated: Texas.
Peak load, Summer IMw)
Annual load Factor(%)
1794 1892 19 NA NA Jl El Paso, Texas and Las Cruces, New Mexico. Vvholesale is 13% of Address: Stanton Tower, 100 North Stanton, El Paso, TX 79901.
+1.7 revenues. Electric revenue breakdown by customer class not avail* Tel.: 915-543-5711. Internet: www.epelectric.com.
%Change Customers (yr-en~ +1.4 +1.6 F~ed Charge Cov. (%) 218 267 263 We estimate that El Paso Electric more volatile.
Company's earnings will advance The utility is required to file a general ANNUAL RATES Past Past Est'd '15*'17 rate case in New Mexico by July of of change (per sh) 10 Yrs. 5 yrs.
- to '21-'23 slightly this year. The utility will have a Revenues 2.0% .. 2.5% full year's worth of the rate increase in 2019. EPE may file sooner; we note that "Cash Flow" 5.5% 1.0%
4.0% Texas that took effect in July of 2017. EPE the portion of Units 3 and 4 of a new gas-Earnings 6.5% 4.5% fired generating station that is allocated to Dividends .. 18.0% 7.0% is also benefiting from above-average cus-Book Value 7.5% 6.5% 4.0% tamer growth that stems from the healthy New Mexico is not reflected in rates. How-economy in El Paso and environs. On the ever,. the regulatory climate in New Mexi-Cal* QUARTERLY REVENUES ($ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year other hand, the weather was favorable for co is difficult (not just for EPE), so the the company in 2017, and we assume company might well wait until it is re-2015 163.8 219.5 289.7 176.9 849.9 quired to file before it puts forth its rate 2016 157.8 217.9 323.2 188.0 886.9 normal weather this year. Our 2018 earn-2017 171.3 251.8 297.5 196.2 916.8 ings estimate, which we lowered by $0.20 application.
2018 170 255 305 195 925 a share, is within management's guidance We expect a dividend hike at the 2019 175 260 315 200 950 of $2.30-$2.65 a share. Next year, the utili- board meeting in May. This has been EARNINGS PER SHARE A ty will benefit from rate relief in Texas the pattern since the directors initiated a Cal* Full common dividend several years ago. We endar Mar.31 Jun.30 Sep.JO Dec.31 Year through transmission and distribution reg-ulatory mechanisms. However . . . estimate an increase of $0.10 a share 2015 .09 .52 1.40 .02 2.03 (7.5%) in the annual disbursement. EPE's 2016 d.14 .55 1.84 .14 2.39 Earnings have become less predic-2017 d.10 .89 1.47 .16 2.42 table. The company owns a 15.8% share of goal is a payout ratio in a range of 55%-
2018 d.15 .75 1.70 .15 2.45 the Palo Verde nuclear station in Arizona. 65%.
2019 d.10 .80 1.75 .15 2.60 Like any utility that owns nuclear assets, This stock has a dividend yield th,at is QUARTERLY DIVIDENDS PAID a EPE invests in a trust to provide funds for
- below the industry mean. Like many Cal* Full utility issues, the recent quotation is endar Mar.31 Jun.JO Sep.JO Dec.31 Year nuclear decommissioning. The gains or 2014 .265 .28 .28 .28 1.11 losses on the nuclear decommissioning within our 2021-2023 Target Price Range.
2015 .28 .295 .295 .295 1.17 trust are now being reflected in the income Accordingly, total return potential over 2016 .295 .31 .31 .31 1.23 statement, instead of through Accumu. that time frame is unspectacular, despite 2017 .31 .335 .335 .335 1.32 lated Other Comprehensive Income on the good dividend growth prospects.
2018 .335 balance sheet. This will make earnings Paul E. Debbas, CFA April 27. 2018 (A) Diluted earnings. Exel. nonrecurring gains dates in late March, June, Sept., and Dec. '16: 9.48%; earned on avg. com. eq., '17: Company's Financial Strength B++
(loss): '03, 81¢; '04, 4¢; '05, (2¢); '06, 13¢; '10, (C) Incl. deferred charges. In '17: $96.0 mill., 8.9%. Regulatory Climate: TX, Average; NM, Stock's Price Stability 90 24¢. Next earnings report due early May. $2.37/sh. (D) In millions. (E) Rate allowed on Below Average. Price Growth Persistence 70 (B) Initial dividend declared 4/11; payment common equity in TX in '17: 9.65%; in NM in Earnings Predictability 75
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wnhout warranties of any kind. -
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part I I I' , :ll!l!'lll!III of nmay be reproduced, resold, stored or transmnted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
18-WSEE-328-RTS EDISON INTERNAT'L NYSE-EIX RECENT
!PRICE 65 ,22 IP/ERATIO 14,3 (Trailing: 14.5)
Median: 12.0 RELATIVE PIE RATIO O, 76 DIV'YLDD 3.8%
TIMELINESS 3 Lowered 3/2/18 High: 60.3 i-=L=ow=:~-4~2=.8~_2=6~.7~--c.23.1 55.71 36.7 39.4 30.4 41.6 32.6 48.0 39.6 54.2 44.3 68.7 44.7 69.6 55.2 78.7 58.0 83.4 62.7 67.6 57.6 Target Price Range 2021 2022 2023 SAFETY 2 Raised 5/3113 LEGENDS . 120 TECHNICAL 4 Raised 4/20/18 * - J::d ~vi1~t~1!sr ~~te
- , ,
- Relative ~rice Strength .....- - ' * *-
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,_B_E_TA=.B~0~(~1.=00===M=ark=e=t)=-----1 O~~~~!~~r!a indicates recession r--t---i----::;r'c:.....::.,._"'-i-.;;::=:::l:;;:;<,;:.'fll,.,...4tr,;;nt#:.:."'~'.:. !!f'--1ft- 1 --i-**-----t---i-*-*._._.--f-*-*._._.-j-. 64 2021-23 PROJECTIONS i;;::=;{+i!':':q*pill!li*;;:::r=~*-~--+="'./C:....1-,..,.,,,.,,Jrc!j*~JJJ1il!'._'.' .'.'.."'111.'.:+*-**.'..'11..':.:_"_:.i"~--+-_jf-*,,_ _j~--+--~--+-_jf-49 Gain AnRetuTomtal " 11111" 1 I 1., .. ,:--,-.-,,*'
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2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 @VALUELINE PUB. LLC1* 1-23 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 35.37 36.43 37.81 38.35 40.20 Revenues per sh 46.75 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 10.35 10.43 11.03 11.45 12.05 "Cash Flow" per sh 14.25 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 4.15 3.94 4.51 4.55 4.70 Earnings per sh A 5.50
- *- .80 1.02 1.10 1.18 1.23 1.25 1.27 1.29 1.31 1.37 1.48 1.73 1.98 2.23 2.45 2.57 Div'd Decl'd per sh e
- 3.10 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 12.97 , 11.46 11.75 13.30 15.05 Cap'I Spending per sh 15.75 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 34.89 36.82 35.82 37.35 38.90 Book Value per sh c 44.50 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 325.81 Common Shs Outst'g 0 325.81 7.8 7.0 37.6 11.7 13.0 _16.0 12.4 9.7 10.3 11.8 9.7 12.7 13.0 14.8 17.9 17.2 Bold fig res are Avg Ann'I P/E Ratio 15.5
.43 .40 1.99 .62 .70 .85 .75 .65 .66 .74 .62 .71 .68 .75 .94 .85 Value Line Relative P/E Ratio .85 esllnate&
.. -- 3.1% 2.6% 2.6% 2.2% 2.7% 4.0% 3.7% 3.4% 3.0% 2.8% 2.6% 2.8% -2.8% 2.9% Avg Ann'I Div'd Yield 3.6%
CAPITAL SlRUCTURE as of 12/31/17 14112 12374 12409 12760 11862 12581 13413 11524 11869 12320 12500 13100 Revenues ($mill) 15200 Total Debt $14516 mill. Due in 5 Yrs $4793 mill. 1266.0 1115.0 1153.0 1112.0 1594.0 1344.0 1539.0 1480.0 1422.0 1603.0 1620 1670 Net Profit ($mill) 1970 LT Debt $11642 mill. LT Interest $569 mill.
(LT interest earned: 4.0x) 30.7% 33.0% 32.1% 25.7% 14.3% 25.2% 22.4% 6.6% 11.1% 5.0% 10.0% 10.0% Income Tax Rate 10.0%
Leases, Uncapitalized Annual rentals $335 mill. 8.9% 10.5% 16.9% 14.8% 8.5% 7.8% 5.8% 8.0% 6.8% 7.2% 8.0% 7.0% AFUDC %to Net Profit 7.0%
Pens. Assets-12/17 $3616 mill. Oblig $4179 mill. 51.2% 49.3% 51.8% 55.3% 45.2% 45.7% 44.1% 45.0% 41.8% 45.6% 48.0% 48.0% Long-Term Debt Ratio 47.5%
Pfd Stock $2193 mill. Pfd Div'd $124 mill. 44.5% 46.5% 44.3% 40.6% 46.2% 46.2% 47.2% 46.7% 49.2% 45.8% 44.0% 44.5% Common Equity Ratio 45.5%
4,800, 198 sh. 4.08%-4. 78%, $25 par, call. $25.50- 21374 21185 23861 24773 20422 21516 23216 24352 24362 25506 27500 28525 Total Capital ($mill) 31800
$28.75/sh.; 3,250,000 sh. variable, noncum., call. 18969 21966 24778
$100; 1,250,000 sh. 6.5%, cum., $100 liq. value; 32116 30273 30455 32981 35085 37000 39050 41125 43675 Net Plant ($mill) 50700 350,000 sh. 6.25%, $1000 liq. value; 460,012 sh. 7.4% 6.9% 6.3% 6.0% 8.9% 7.3% 7.7% 7.1% 6.9% 7.3% 7.0% 7.0% Return on Total Cap'I 7.5%
5.1 %-5. 75%, $2500 liq. value. 12.1% 10.4% 10.0% 10.0% 14.2% 11.5% 11.9% 11.1% 10.0% 11.6% 11.5% 11.0% Return on Shr. Equity 12.0%
Common Stock 325,811,206 shs. as of 2/20/18 12.8% 10.8% 10.4% 10.5% 15.9% 12.5% 13.0% 12.0% .10.8% 12.7% 12.5% 12.0% Return on Com Equity E 12.5%
MARKET CAP: $21 billion (Large Cap) 8.6% 6.7% 6.5% 6.3% 11.4% 8.1% 8.8% 7.2% 5.6% 6.6% 5.5% 5.5% Retained to Com Eq 6.0%
ELECTRIC OPERATING STATISTICS 35% 41% 40% 43% 32% 40% 37% 44% 53% 52% 57% 58% All Div'ds to Net Prof 58%
%Change Relail Sales (!Mil) 2015
-1.4 2016
-2.6 2 °;~ t-B-U-SI-N~ES_S_:_E_d~is-on-ln-te~rn-at-io-na-l~(f-orm-e-rly~SC_E_C_o~~-)-is-a~ho-ld-in-g~d-e-nt-ia-l,~3-7o/c-,;-c-om~m-er-ci-al~,4-4_%_;-in~du-s-tri-al-,6-o/c-,;-o-th-er-,-13_%__~G-en_e_ra--~
Avg. lndu~. Use (MWHI 703 664 NA company for Southern California Edison Company (SCE), which ting sources: gas, 6%; nuclear, 6%; hydro, 5%; purchased, 83%.
Avg. lndu~. Revs..P.er K\!ni (¢) 9.07 6.51 NA supplies electricity to 5.1 mill. customers in a 50,000-sq.-mi. area in Fuel costs: 38% of revs. '17 reported depr. rate: 3.8%. Has 12,500 Capac~ at Peak (Mw~ NA NA NA central, coastal, & southern CA (excl. Los Angeles & San Diego). empls. Chairman: William P. Sullivan. Pres. & CEO: Pedro J. Piz-Peak load, Summer ) 23079 23091 Annual load Factor(,) 52.2 50.7 235~i Edison Energy is an energy svcs. co. Disc. Edison Mission Energy zaro. Inc.: CA Address: 2244 Walnut Grove Ave., P.O. Box 976,
%Change Cu~omers (yr-end) +.6 +.5 +.7 (independent power producer) in '12. Elec. rev. breakdown: resi- Rosemead, CA 91770. Tel.: 626-302-2222. Web: www.edison.com.
F~edChargeCov.(%) 247 246 t------------------------------------------1 Investors remain concerned about the the beginning of 2018.) The utility's three-241 t-A_N_N_U~A-L-R/l~T~E-S-P-as-t--Pa_s_t_E_s-t'-d-,1-5_-,1-i7 possible wildfire liability of Edison In- year capital spending plan calls for $1.4 of change (per sh) 10 Yrs. SYrs. to '21-'23 ternational's utility subsidiary. billion for grid modernization, which is Revenues -.5% -.5% 4.0% Southern California Edison's service area somewhat controversial because the Cali-
"Cash Flow" 4.0% 3.5% 5.0% had wildfires in the fall of 2017. The cause fornia commission has not been asked to Earnings 2.5% 2.5% 4.5%
Dividends 6.0% 9.0% 8.0% of the wildfires has not yet been deter- approve such spending in previous rate Book Value 4.5% 3.0% 3.5% mined, but SCE has already been hit with cases. An order is expected by yearend.
t--C-al---.--Q-UA_R_T-ER-LY_R_EV_E_N-UE-S-($_m_il_l.)-,-F-ul-il some lawsuits alleging that its power lines Tax reform is slightly negative for the endar Mar.31 Jun.30 Sep.30 Dec.31 Year were at fault. (It has $1 billion in liability company. Edison International has about 1-2-0-15-+-2-1--
52 2908 3763
- - -+-.ccc.:..'--I 234 1 11 524 insurance.) Under California's inverse con- $1.75 billion of long-term debt at the 2016 2440 2777 3767 2885 11869 demnation law, a utility can be held liable parent level, so corporate interest and 2017 2463 2965 3672 3220 12320 if its power lines contributed to the wild- other expenses will have a lower tax 2018 2500 3000 3800 3200 12500 fires, even if the utility followed accepted shield. This is also true for the company's 2019 2600 3150 4000 3350 13100 inspection and safety rules. If this occurs, nonutility energy-services subsidiary, t--C-al---+---EA-R-NI-NGS-P-ER_S_H-AR_E_A---+-F-ul-il there is no assurance that the utility will Edison Energy, which is still in its start-endar Mar.31 Jun.30 Sep.30 Dec.31 Year be allowed to pass these costs through to up phase and is in the red. Management 1-2-0-15--t-.-91--1-.1-5--1'-.- --_---+......:..:. :;_c....i 15 94 4 15 ratepayers. So, the company is pursuing a estimates that the corporate and non-2016 .85 .86 1.27 .96 3.94 three-pronged strategy to address this utility drag on earnings will amount to 2017 1.11 .85 1.43 1.12 4.51 risk, seeking legislative, regulatory, and $0.25-$0.30 a share this year. Note that 2018 1.10 .90 1.45 1.10 4.55 judicial solutions to this problem. the company is not providing earnings 2019 1.15 .90 1.50 1.15 4.70 SCE is awaiting an order on its gener- guidance as long as the general rate case 1--C-aJ-.-+--Q-UA-R-TE-R-LY_D_IV-ID-EN_D_S_PA-ID_e_.__,_F-ul-,I al rate case. The utility has revised its is pending.
endar Mar.31 Jun.30 Sec.30 Dec.31 Year request to pass through to customers the The wildfire risks hurt the stock last 1- - - -~_= ~~. = = ~~_~ ~ ~~_- - --.4-, benefits of federal tax reform. SCE is ask- year, and the price has risen .just 2014 355 355 355 355 1 2 201S .41 75 .4175 .41 75 .4175 1.67 ing for a reduction of $106 million in 2018 slightly in 2018. The dividend yield and 2016 .48 .48 .48 .48 1.92 and increases of $431 million and $503 3- to 5-year total return potential are 2017 .5425 .5425 .5425 .5425 2.17 million at the start of 2019 and 2020, res- above average for this industry.
2018 .605 .605 pectively. (The order will be retroactive to Paul E. Debbas, CFA April 27, 2018 (A) Di!. EPS. Exel. nonrec. gains (losses): '02, lions: '12, ($5.11); '13, 11¢; '14, 57¢; '15, 11¢. charges. In '17: $15.08/sh. (D) In millions. (E) Company's Financial Strength A
$1.48; '03, (12¢); '04, $2.12; '09, (64¢); '10, Next earnings report due late July. (B) Div'ds Rate base: net orig. cost. Rate allowed on com. Stock's Price Stability 90 54¢; '11, ($3.33); '13, ($1.12); '15, ($1.18); '17, paid late Jan., Apr., July, & Oct.
- Div'd rein- eq. in '15: 10.45%; earned on avg .. com. eq., Price Growth Persistence 50
($1.37); gains (Joss) from discontinued opera- vestment plan available. (C) Incl. deferred '17: 12.2%. Regulatory Climate: Average.
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wtthout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly tor subscriber's own, non-commercial, internal use. No part Ina."'"***~* I '
of It may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating 01 marketing any printed or electronic publication, service or product.
Earnings Predictability
- Hll"'11!HI II 60
18-WSEE-328-RTS
'IDACORn INC t-------,,--r+-- 1 _ 1 N,--YS_E----rlDA_-,------r-__._P,--RICE~-',--J-RAT~IO_ ,~Med~ian_:
IRECENT 88 84 IP/E 211 (Trailing:21.1) RELATIVE 112 DIV'D 2701.~ 14.---101--P/E_RAT~IO_,---,--L_YLD~-'~/O.JIIUW.;ll~--1 TIMELINESS 2 Raised 1 22117 21 High: 39.2 35. 1 I 32.8 37.8 42.7 45.7 54.7
- 70.1 70.5 83.4 100.0 91.4 Target Price Range Low: 30.1 21.9 20.9 30.0 33.9 38.2 43.1 50.2 55.4 65.0 77.5 79.6 2021 2022 2023 SAFETY 2 Raised 8/2/13 _L_EG~.~r:Dividends p sh f--t-----l--+~---1--+----+--+----+--+----+--+----+--+---+ 120 TECHNICAL 3 Lowered2/23/18 .... i~i~f~eb~r/gleg\~ln~~e t---+-----1--+----+--+---+--+---+-~,+---+--+---+--+-.-
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48 Ann'I Total 1- i Gain (N'll Return 3%
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(-2'5,}. -4% .***** / '_I!_ *I 0 24 Insider Decisions 1--~=**r:;~?*=-*1:i,.'-"::,.**'.,_,*-+-'-'c-1 1 0 0 00
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.::0-::.::-0.,o..,,.,,.o_o_o 3Q2017 4Q2017 1---+--.H-+'>-111~11111111 1111 I I II
." TOT'*STOCK RETURN 3/18 THIS VL ARITH..
INDEX
- 8 Percent 15 to Buy 139 116 127 shares 10 II I," Ill * * , l 1 yr. 9.2 9.7 ::
loSell 91 113 86 traded 5 -11111 '"' 1111 111111. ,11 *" 111.11 .. , , * .. 111 3yr. 52.7 24.3 _
,__Hld_'s~(IOO~Ol,--45_9_85~4_5_7_08~_38_2_00_.__ _ _ ___. 11111 1111111111 1111111111 1111111111 nflllllll 1111111111 m Syr. 111.6 68.8 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUELINEPUB.LLCi, 1-23 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 25.23 25.04 26.76 26.60 27.00 Revenues per sh 28.75 4.08 3.50 4.12 3.87 4.58 4.11 4.27 5.07 5.35 5.84 5.93 6.29 6.58 6.70 6.86 7.50 7.65 8.05 "Cash Flow" per sh 9.25 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 3.87 3.94 4.21 4.15 4.35 Earnings per sh A 4.75 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 1.92 2.08 2.24 2.40 2.56 Div'd Decl'd per sh e
- t 3.05 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 5.84 5.89 5.66 6.25 6.40 Cap'I Spending per sh 6.75 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 40.88 42.74 44.65 46.40 48.15 Book Value per sh c 53.25 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 50.34 50.40 50.42 50.40 50.40 Common Shs Outst'g O 50.40 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 16.2 19.1 20.6 Bold fig res are Avg Ann'I P/E Ratio 16.0 1.03 1.51 .82 .89 .82 .97 .84 .68 .75 .72 .79 .75 .77 .82 1.00 1.04 Value Line Relative P/E Ratio .90 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% 3.1% 2.8% 2.6% estlnates Avg Ann'I Div'd Yield 4.0%
CAPITAL STRUCTURE as of 12/31/17 960.4 1049.8 1036.0 1026.8 1080.7 1246.2 1282.5 1270.3 1262.0 1349.5 1340 1360 Revenues ($mill) 1450 Total Debt $1746. 1 mill. Due in 5 Yrs $305.0 mill. 98.4 124.4 142.5 166.9 168.9 182.4 193.5 194.7 198.3 212.4 210 220 Net Profit ($mill) 245 LT Debl$1746. 1 mill. LT Interest $82.0 mill. 16.3% 15.2% .. .. 13.4% 28.3% 8.0% 19.0% 15.5% 18.6% 10.5% 10.5% Income Tax Rate 10.5%
(LT interest earned: 3.9x) 10.2% 10.5% 19.1% 23.3% 20.3% 12.3% 13.6% 16.3% 16.3% 13.9% 14.0% 14.0% AFUDC %to Net Profit 14.0%
Pension Assets-12/17 $697.7 *mill. 47.6% 50.2% 49.3% 45.6% 45.5% 46.6% 45.3% 45.6% 44.8% 43.7% 44.0% 42.0% Long-Tenn Debt Ratio 44.0%
52.4% 49.8% 50.7% 54.4% 54.5% 53.4% 54.7% 54.4% 55.2% 56.3%
Oblig $999.3 mill. t--=-c=--=-~==-c-t--=c~c-+~~t--=c~c-+~,-,-+-c-c=-c,-+-=-'--1-,-,~c-+-~,.,..t--56~.0~%c-+-_58~.0cc%=-+=Cccom~mc,,o.c.cn~E_,qc..,ui.,,_,tvR=at_io_+-5~6.=0%=,-;
2485.9 2807.1 3020.4 3045.2 3225.4 3465.9 3567.6 3783.3 3898.5 3997.5 4180 4165 Total Capital ($mill) 4775 Pfd Stock None 2758.2 2917.0 3161.4 3406.6 3536.0 3665.0 3833.5 3992.4 4172.0 4283.9 4425 4560 Net Plant ($mill) 4850 Common Stock 50,392,360 shs. 5.3% 5.7% 6.0% 6.8% 6.5% 6.4% 6.6% 6.2% 6.1% 6.3% 6.0% 6.5% Return on Total Cap'I 6.0%
as of 2/16/18 7.6% 8.9% 9.3% 10.1% 9.6% 9.9% 9.9% 9.5% 9.2% 9.4% 9.0% 9.0% Return on Shr. l:quity 9.0%
7.6% 8.9% 9.3% 10.1% 9.6% 9.9% 9.9% 9.5% 9.2% 9.4% 9.0% 9.0% Return on Com Equity E 9.0%
MARKET CAP: $4.5 billion (Mid Cap) 3.4% 4.8% 5.5% 6.5% 5.7% 5.6% 5.4% 4.8% 4.3% 4.4% 4.0% 4.0% Retained to Com Eq 3.5%
ELECTRIC OPERATING STATISTICS 55% 46% 41% 36% 41% 43% 46% 50% 53% 53% 57% 59% All Div'ds to Net Prof 63%
2015 2016 ~~~1--B-U-SI_NLES_S_:_ID_ALC_O_R_P-,ILn-c.-is_a_,._ho-ld-in_g_cLom_p_a-ny_fLo-rl-da_h_oLP-~-e-r-'-r-ig-at-io-n,L1-1_%_;_mLhe-r.-1-0_%L.-G-e-ne-raLti-ng-so-u-~-es_:_h-yd_r_o,-5-0L%-;_w_a_l.~
%ChangeRetailSales(K\',\l) +1.2 -.5 Avg. lmfust. Use (MWH) NA NA NA Company, a regulated electric utility that serves 545,000 customers 18%; gas, 8%; purchased, 24%. Fuel costs: 33% of revenues. '17 Avg.lndust.Revs1eri(1Mj (¢) 5.70 5.63 5.83 throughout a 24,000-square-mile area in southern Idaho and east- reported depreciation rate: 2.9%. Has 2,000 employees. Chairman:
Capacity at Peak (MW) NA NA ~~ ern Oregon (population: 1 million). Most of the company's revenues Robert A. Tinstman. President & CEO: Darrel T. Anderson. In-Peak load, Summer IMw) 3402 3299 34NA are derived from the Idaho portion of its service area. Revenue wrporated: Idaho. Address: 1221 W. Idaho St., Boise, Idaho Annual Load Factor(%) NA NA
%ChangeCustomers(yr-end) +1.4 +1.8 +2.0 breakdown: residential, 41%; commercial, 24%; industrial, 14%; ir- 83702. Telephone: 208-388-2200. Internet: www.idawrpinc.com.
t-------------------------------------------1 F~ed Charge Gov. (%) 307 295 329 IDACORP's 10-year streak of earnings 2017 was driven in part by weather) due ANNUAL RATES Past Past Est'd '15-'17 growth might. well come to an end in to the effects of energy efficiency. The util-of change (per sh) 10 Yrs. 5Yrs. to '21-'23 2018. This is despite the performance of ity's cost control has been effective, too.
Revenues 2.5% 4.0% 2.0% the company's utility subsidiary, Idaho We forecast a resumption of profit "Cash Flow" 5.5% 4.0% 4.5% Power, which is faring well, is financially growth in 2019. We think IDACORP will Earnings 7.5% 4.5% 3.5% sound, and has good growth prospects. A benefit from the growth of Idaho Power.
Dividends 5.5% 10.5% 6.5%
Book Value 5.5% 5.5% 3.5% year ago, IDACORP's income benefited Our $4.35-a-share estimate would produce QUARTERLY REVENUES($ mill.) Full from some tax adjustments. Favorable an increase of 5%.
Cal-endar Mar.31 Jun.30 Sep.30 Dec.31 Year weather conditions, helped, as well. Our The utility has a regulatory mechan-earnings estimate of $4.15 a share, which ism to supplement its income, if 2015 279.4 336.3 369.2 285.4 1270.3 2016 281.0 315.4 372.0 293.6 1262.0 we trimmed by a nickel, is within the com- necessary. If Idaho Power's earned re-2017 302.6 333.0 408.3 305.6 1349.5 pany's targeted range of $4.10-$4.25. turn on equity falls below 9.5% through 2018 310 335 390 305 1340 Given that IDACORP earned $4.21 a 2019, the utility may use up to $25 million 2019 315 340 395 310 1360 share in 201 7, another year of profit of accumulated deferred investment tax Cal- EARNINGS PER SHARE A Full growth is hardly out of the question, based credits annually to bring its ROE to that endar Mar.31 Jun.30 Sep.30 Dec.31 Year on the company's guidance. level. (A proposed regulatory settlement 2015 .47 1.31 1.46 .63 3.87 We expect dividend growth to contin- would extend this mechanism indefinitely 2016 .51 1.12 1.65 .66 3.94 ue, even if earnings growth is inter- beyond next year.) Note that the ROEs 2017 .66 .99 1.80 .77 4.21 rupted. Management anticipates recom- shown in the statistical array are for 2018 .60 1.00 1.85 .70 4.15 mending to the board annual increases of IDACORP as a whole, not just its utility 2019 .65 1.05 1.90 .75 4.35 at least 5%. The company is targeting a subsidiary.
Cal- QUARTERLY DIVIDENDS PAID 8
- t Full payout ratio in a range of 50%-60%. This stock is timely, but is priced ex-endar Mar.31 Jun.30 Sea.30 Dec.31 Year Idaho Power is performing well. The pensively. The dividend yield is below economy of the company's service area is average for a utility. The recent quotation 2014 .43 .43 .43 .47 1. 76 healthy. Customer growth was 2.0% last is near the upper end of our 2021-2023 2015 .47 .47 .47 .51 1.92 2016 .51 .51 .51 .55 2.08 year, which is more than double the indus- Target Price Range. Accordingly, total re-2017 .55 .55 .55 .59 2.24 try norm. Kilowatt-hour sales generally turn potential is negligible.
2018 .59 aren't rising as fast (the 2.6% increase in Paul E. Debbas, CFA April 27, 2018 (A) Diluted EPS. Exel. nonrecurring gains paid in late Feb., May, Aug., and Nov.
- Div'd Net original cost. Rate allowed on common Company's Financial Strength A (loss): '03, 26¢; '05, (24¢); '06, 17¢. '17 earn- reinvestment plan available. t Shareholder in- equity in '11: 10% (imputed); earned on avg. Stock's Price Stability 95 ings don't sum due to rounding. Next earnings vestment plan available. (C) Incl. intangibles. In com. eq., '17: 9.6%. Regulatory Climate: Price Growth Persistence 90 report due early May. (B) Div'ds historically '17: $21.49/sh. (D) In millions. (E) Rate base: Above Average. Earnings Predictability 95
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed lo be reliable and is provided wtthout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of tt may be reproduced, resold, stored or transmttted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
18-WSEE-328-RTS 0 0 1--A_L_LI_A----=-NT_EN_E_R-.-G_Y_NY,--SE----'-L-'-'-r-NT_.-------1-l~-,-~fc_Et__,.3_8_.1-,-7-'--l~--.T10_1::-:-7.,--7(_~~-.-~i~~-;1!_:0+-~p_J1-,-~t_0.__,93__,_l -,----3.--.5°_YoBa_----1 TIMELINESS 2 Raised3/9/18 High: 23.3 21.2 15.8 18.8 22.2
_i~
23.8 27.1 34.9 35.4. 41.D 45.6 42.7 Target Price Range Low: 17.5 11.4 10.2 14.6 17.0 20.9 21.9 25.0 27.1 30.4 36.6 36.8 2021 2022 2023 SAFETY 2 Raised 9/28/07 LEGENDS TECHNICAL 3 Lowered 3/2/18 - gii~:d ~"tt~~!sf ~~te 1-+----1--+----11----t-----11----t-----1--+-----1--+--- --1--+-----1-BO BETA .70 (1.00=Market)
- * *
- Relative ~rice Strength 2-for-1 spl! 5/16 l--+----t---t-----1,---t-----11----+----:- **---1---t-----1---t-----1---t----t-60 50 2021-23 PROJECTIONS O~~~~~/.;'r~aindicatesrecession ~
- _..- *--.,.,, *** ***** ****** 40 Ann'I Total 1 / 1 1 ** ,, 111* . .,11 *- ***** -----*
Price Gain Return : 1
~ , *... ,
- 30 High 45 (+20%1 8% 1---+:-::--il--+-+- 1
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1 t==9'--'""=;-:-:-;;;;;p-r<"l[' r'--r---t--jr---t---i---t---j---t---j---t-20 1f"'"j'"'".:.:.-'..cc"1 Insider Decisions ,,,,,*" ' ' 1 1~ * . I , 11i1 1" ' 15
- ""'*~I ""*f"'l:1'1111 11 M J"J AS ON D J to Buy 1 o o o o o o o o ****- ' '('I,, ,*, * .'"' ...*"*,.,, * *. *********............. 10 OptionsOOOOOOOOO I I ** .......... ****
to Soll 1 O O O 1 O O O O Institutional Decisions 2Q2017 3Q2017 4Q2017 Percent 24 1 I I
% TOT. RETURN 2118 THIS STOCK VLARITH.'
INDEX
~7.5 to Buy 198 194 190 shares 16 ' I " I I 1 yr. 1.0 10.1 ~
tos,11 188 187 165 traded 8 I ,. 111 ilmhlll!lhl*lo.l " II I "' ,, I ,, II 3yr. 34.3 24.2 -
Hld's(DODl 179256 182717 166325 lllllllllllll llllllllWIIIIIIII 11111111111111111111 11111111111 1111111111111111111111111111111111 1111111111 II Syr. 92.2 76.2 Alliant Energy, formerly called Interstate En- 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 @VALUELINEPUB.LLC, 1-23 ergy Corporation, was formed on April 21, 16.67 15.51 15.40 16.51 13.94 14.77 15.10 14.34 14.58 14.62 15.30 15.55 Revenues per sh 17.75 1998 through the merger of WPL Holdings, 2.28 2.10 2.60 2.75 2.95 3.34 3.44 3.45 3.45 3.97 4.25 4.45 "Cash Flow" per sh 5.00 IES Industries, and Interstate Power. WPL 1.27 .95 1.38 1.38 1.53 1.65 1.74 1.69 1.65 1.99 2.10 2.25 Earnings per sh A 2.60 stockholders received one share of Inter- .70 .75 .79 .85 .90 .94 1.02 1.10 1.18 1.26 1.34 1.42 Div'd Decl'd per sh e
- t 1.66 state Energy stock for each WPL share, IES 3.98 5.43 3.91 3.03 5.22 3.32 3.78 4.25 5.26 6.34 6.75 7.10 Cap'I Spending per sh 5.30 stockholders received 1.14 Interstate Ener- 12.78 12.54 13.05 13.57 14.12 14.79 15.54 16.41 16.96 18.08 19.00 20.25 BookValuepersh c 22.85 gy shares for each IES share, and Interstate 220.90 221.31 221.79 222.04 221.97 221.89 221.87 226.92 227.67 23,1.35 233.00 235.00 Common Shs Outst'g o 235.00 Power stockholders received 1. 11 Interstate 13.4 13.9 12.5 14.5 14.5 15.3 16.6 18.1 22.3 20.6 Bold fig res.,. Avg Ann'I PIE Ratio 15.0 Energy shares for each Interstate Power .81 .93 .80 .91 .92 .86 .87 .91 1.17 1.01 Value Lin* Relative PIE Ratio .85 share. 4.1% 5.7% 4.6% 4.3% 4.1% 3.7% 3.5% 3.6% 3.2% 3.1% estin ates Avg Ann'I Div'd Yield 4.3%
CAPITAL STRUCTURE as of 12/31/17 3681.7 3432.8 3416.1 3665.3 3094.5 3276.8 3350.3 3253.6 3320.0 3382.2 3560 3650 Revenues ($mill) 4175 Total Debt $5186.5 mill. Due in 5 Yrs $1500.D mill. 280.0 208.6 303.9 304.4 337.8 382.1 385.5 380.7 373.8 455.9 490 530 Net Profit ($mill) 610 LT Debt $4010.6 mill. LTlnterest $180.D mill. 33.4% -- 30.1% 19.0% 21.5% 12.4% 10.1% 15.3% 13.4% 12.5% 12.0% 12.0% Income Tax Rate 12.0%
- r (L interest earned: .ox) 4
-- .. -- -- -* *- *- 6.5% 7.0% 7.0% 7.0% 7.0% AFUDC %to Net Profit 7.0%
Pension Assets-12/17 $950.7 mill. Oblig. $1303.1 36.3% 44.3% 46.3% 45.7% 48.4% 46.1% 49.7% 48.6% 52.8% 49.0% 50.0% 50.0% Long-Term Debt Ratio 50.0%
mill. 58.6% 51.2% 49.5% 50.9% 48.4% 50.8% 47.5% 51.4% 47.2% 51.0% 50.0% 50.0% Cominon Equity Ratio 50.0%
Pfd Stock $400.D mill. Pfd Div'd $10.2 mill. 4815.6 5423.0 5840.8 5921.2 6476.6 6461.0 7257.2 7246.3 8177.6 8192.8 8300 8400 Total Capital ($mill) 8700 16,DDD,DOD shs. 5353.5 6203.0 6730.6 7037.1 7838.0 7147.3 6442.0 8970.2 9809.9 10797.9 11125 11645 Net Plant ($mill) 12900 common stock 231,348,646 shs. 7.0% 5.1% 6.6% 6.4% 6.3% 7.0% 6.3% 6.3% 5.6% 5.6% 6.0% 6.5% Return on Total Cap'I 7.0%
9.1% 6.9% 9.7% 9.5% 10.1% 11.0% 10.6% 10.2% 9.7% 10.9% 11.0% 11.0% Return on Shr. Equity 11.5%
9.3% 6.8% 9.9% 9.5% 10.3% 11.3% 10.9% 10.2% 9.7% 10.9% 11.0% 11.0% Return on Com Equity E 11.5%
MARKET CAP: $8.8 billion (Large Cap) 3.8% .9% 3.8% 3.3% 3.9% 4.9% 4.3% 3.6% 2.8% 4.0% 4.0% 4.0% Retained to Com Eq 4.0%
ELECTRIC OPERATING STATISTICS 62% 88% 64% *67% 64% 57% 59% 65% 72% 63% 64% 63% All Div'ds to Net Prof 64%
2015 2016 2~1~ 1--8-US_I_N~ES_S_:_A_lli~an_t_E-ne-rg~y-C-o-rp-.,~f-or_m_e-rly~n-a_m_e_d~ln-te-rs-ta-te~En-e-r-~s-o-ur-ce-s~,-20-1-7:-c~o-al-,4-0-%~;-ga_s_,-17~'/c-,;-o-th-e-r,-43-%-,.-F-u-el_c_os~ts_:_4_5'/c-,.,
%Change Retail Sales (KWH) -.1 +2.0 Avg. lndu~. Use (M'Mi) 11735 11987 12102 gy, is a holding company formed through the merger of WPL Hold- of revs. 2017 depreciation rate: 5.5%. Estimated plant age: 15 Avg. lndu~. RevsJl_er KWH (i) 6.92 7.04 7.16 ings, IES Industries, and Interstate Power. Supplies electricity, gas, years. Has approximately 3,989 employees. Chairman & Chief Ex-Capacity at Peak (MIi) 5385 5615 ~~i~ and other services in Wisconsin, Iowa, and Minnesota. Elect. revs. ecutive Officer: Patricia L. Kampling. Incorporated: Wisconsin. Ad-Peak load, Summer (Mw) 5385 5615 Annual load Factor(Yo) NA NA NA by state: WI; 38%; IA, 61%; MN, 1%. Elect. rev.: residential, 36%; dress: 4902 N. Biltmore Lane, Madison, Wisconsin 53718. Tele-
%Change Cuslomers (yr-end) +.3 +1.0 +.4 commercial, 24%; industrial, 30%; wholesale, 8%; other, 2%. Fuel phone: 608-458-3311. Internet: www.alliantenergy.com.
1------------------------------------------t F~ed Charge Cov. (%) 315 295 319 Alliant Energy's largest utility subsid- much of the anticipated savings will be re-ANNUAL RATES Past Past Est'd '14-'16 iary has reached a settlement of its turned to customers through fewer/lower of change (per sh) 10 Yrs. 5Yrs. to '21-'23 rate case. Under the agreement, electric rate increases over time.
Revenues .5% -1.5% 3.0% rates for Interstate Power and Light Com- Wind energy remains an area of focus "Cash Flow" 3.5% 6.5% 5.5% pany (IPL) would rise $130 million (7.8%) for Alliant. In December, the utility Earnings 5.0% 6.5% 6.5%
Dividends 7.5% 6.5% 6.0% in 2018. That is down from the original agreed to purchase English -Farms Wind Book Value 4.0% 4.5% 5.0% $176 million (11.6%) reque~t. but within Farm for an undisclosed sum. The 170-Cal, QUARTERLY REVENUES ($ mill.) our range of estimates. The Iowa Utilities megawatt, Iowa-based project is expected Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year Board also approved a return on common to power approximately 75,000 homes 2015 897.4 717.2 898.9 740.1 3253.6 equity of 9.6% and said that temporary upon completion. Alliant is aiming to gen-2016 843.8 754.2 925.0 797.0 3320.0 rates, which have been in effect since April erate at least one-third of its Iowa energy 2017 853.9 765.3 906.9 856.1 3382.2 2017, would remain until the board mix from wind starting in 2020. .
2018 950 790 945 875 3560 reviews and approves tariff filings to be The board raised the dividend in the 2019 960 815 975 900 3650 made by Alliant. The company said it first quarter of 2018. This is the usual Cal- EARNINGS PER SHARE A Full would use the funds to upgrade power timing of the annual increase. The direc-endar Mar.31 Jun.30 Sep.30 Dec.31 Year grids and improve facilities like the Mar- tors boosted the yearly disbursement by 2015 .44 .30 .80 .15 1.69 shalltown natural gas generating station. $0.08 a share (6.3%), the same increase as 2016 .43 .37 .57 .28 1.65 Earnings should advance in 2018 and in each of the past four years. Alliant is 2017 .44 .41 .73 .41 1.99 2019. Each year, the utility is expected to tar~eting a payout ratio of 60%-70% .
2018 .50 .40 .85 .35 2.10 benefit from electric and gas rate increases This good-quality stock is well ranked 2019 .53 .43 .90 .39 2.25 at IPL and Wisconsin Power and Light for year-ahead relative price perform-Cal- QUARTERLY DIVIDENDS PAID e -t Full Company (WPL). Our 2018 profit estimate ance. The dividend yield is slightly below endar Mar.31 Jun.30 Seo.30 Dec.31 Year is near the midpoint of management's the median for a utility. Appreciation 2014 .255 .255 .255 .255 1.02 guidance range of $2.04-$2.18 a share, potential, while improved since our De-2015 .275 .275 .275 .275 1.10 while our 2019 estimate calls for 7% year- cember report, is still well below the value 2016 .295 .295 .295 .295 1.18 on-year growth. It should be noted that Line median. Accordingly, we advise long-2017 .315 .315 .315 .315 1.26 tax reform is not forecasted to have a ma- term investors to wait on the sidelines .
2018 .335 terial impact on earnings. This is because Daniel Henigson March 16, 2018 (A) Diluted EPS. Exel. nonrecur. gains (losses): Aug., and Nov.
- Div'd reinvest. plan avail. t Orig. cost. Rates all'd on com. eq. in IA in '17: Company's Financial Strength A
'DB, 4¢; '09, (44¢); '10, (8¢); '11, (1¢); '12, (8¢). Shareholder invest. plan avail. (C) Incl. 10.5%; in WI in '17 Regul. Clim.: WI, Above Stock's Price Stability 95 N~~t earnings _report ~ue_ early May. (8) deferr~d chgs. In '17: $69.7 mill., $0.30/sh. (D) Avg.; IA, Avg. Pric~ Growth ~ersi~~ence 90 D1v1dends h1stoncally paid 1n mid-Feb., May, In millions, adJusted for split. (E) Rate base:
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided w!hout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRD_RS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, intemal_use. No part of it may be reproduced, resold, stored or transmitted in any pnnted, electronic or other form, or used for generating or marketing an printed or electronic publication, service or product.
IllEammgs Predtctabtlily I Ill~,.~, I ' *
- 11 1 90
18-WSEE-328-RTS 0
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TIMELINESS 3 Lowered2123118 High: 36.7 29.7 26.8 30.6 36.6 38.0 47.2 58.7 59.7 48.4 63.8 52.2 64.5 55.7 59.8 50.0 Target Price Range 2021 2022 2023 i-=L'-"o-'-'w'-:.,__=-24-'-'-=-5.,__-'-16"-'.=-5-'---;18.5 23.8 27.4 33.0 35.1 42.6 SAFETY 3 New 5/4/12 _L_EG~-~f: Dividends Psh 120 TECHNICAL 5 Lowered4/6/1B .... ~~J~~eb~r/~~e~;~n~~e 1*0=0===M=ark=e=t)=-__, o~g~~~/ir~a indicates recession t--+-----l---+-----l--+----t...,,,.-'""'=i-_.._:.....:-==i--,,....,=1---+--- -t--+--_**-*--+*_*-_-_*+* 64
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2021*23 PROJECTIONS , , I~ .. ,..Jff..., 11,*u 1'h" 11 111 .,,.,~.,: r1-ll... ----- -----* 48 Price Gain Ann'I Total Return ........... ,
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__./ .. 1 ., 1, 1.,,, 1, 1* 111111 High 15 (+35%1 11% /"..t**.'-**"c._**- .t-"1*1r,::i.,,,:t1_:---:- .-t=.+/-1 =Ri?.7::7f.'ir"'flJJ-F"--4---t---t-- 1 1 1---t--1 1---t---t---t---t----t-32 1e:.;1l_"'_"t-'_ _t---+---ll--+--t-:---+--t--+---11--+---l--+ 24 1
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- :~ri 1~1 i6g Hld'slODD 56186 53930 45947 traded
~~ shares 20 10 I .::1 .,. II. II, .. I h 111111111111111111111 1111111111111111111111 1111111111 111111111111111111111 llllllli11111111IIIJ111 1111111111 II I I .II ,I II g:: 1t~
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2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUELINEPUB.LLCi,1-23 29.18 32.57 31.49 30.79 35.09 31.72 30.66 30.80 28.76 29.80 25.68 25.21 26.01 26.45 26.25 27.00 Revenues per sh 29.50 3.20 4.00 3.62 3.70 4.40 4.62 4.76 5.42 5.18 5.45 5.39 5.92 6.74 6.76 6.95 7.30 "Cash Flow" per sh 8.25
- d14.32 1.71 1.31 1.44 1.77 2.02 2.14 2.53 2.26 2.46 2.99 2.90 3.39 3.34 3.45 3.55 Earnings per sh A 4.00 1.00 1.24 1.28 1.32 1.34 1.36 1.44 1.48 1.52 1.60 1.92 2.00 2.10 220 230 Div'd Decl'd per sh B
- t 2.60 2.25 2.26 2.81 3.00 3.47 5.26 6.30 5.20 5.89 5.95 5.76 5.89 5.96 5.60 5.70 6.70 Cap'I Spending per sh 6.25 19.92 20.60 20.65 21.12 21.25 21.86 22.64 23.68 25.09 26.60 31.50 33.22 34.68 36.44 37.95 39.10 Book Value per sh c 42.75 35.60 35.79 35.97 38.97 35.93 36.00 36.23 36.28 37.22 38.75 46.91 48.17 48.33 49.37 50.25 50.40 Common Shs Outst'g 0 51.00 17.1 26.0 21.7 13.9 11.5 12.9 12.6 15.7 16.9 16.2 18.4 17.2 17.8 Bold fig res are Avg Ann'I PIE Ratio 16.0
.91 1.40 1.15 .84 .77 .82 .79 1.00 .95 .85 .93 .90 .89 Value Line Relative P/E Ratio .90
-- -- -- 3.4% 3.6% 4.1% 5.4% 5.7% 4.9% 4.5% 4.2% 3.7% 3.3% 3.6% 3.4% 3.5% estin ates Avg Ann'I Div'd Yield 4.1%
CAPITAL STRUClURE as of 12/31/17 1260.8 1141.9 1110.7 1117.3 1070.3 1154.5 1204.9 1214.3 1257.2 1305.7 1320 1360 Revenues ($mill) 1500 Total Debt $2137.3 mill. Due in 5 Yrs $332.0 mill. ITT ru ru ~ m ~ ~ 1~ ~ ~ 170 180 Net Profit ($mill) 205 LT Debt $1815.6 mill. LT Interest $83.5 mill. 37.3% 17.2% 25.0% 9.8% 9.6% 13.2% ** 13.7% 13.7% 7.6% 2.5% 3.5% Income Tax Rate 6.5%
Incl. $22.2 mill. capitalized leases.
(LT interest earned: 3.1x) 2.3% 4.4% 14.2% 3.3% 9.4% 8.7% 8.9% 9.8% 4.3% 5.2% 6.0% 6.0% AFUDC %to Net Profit 5.0%
46.8% 56.4% 57.2% 52.2% 53.8% 53.5% 53.4% 53.1% 52.0% 50.2% 49.5% 48.5% Long-Tenn Debt Ratio 46.0%
53.2% 43.6% 42.8% 47.8'/, 46.2% 46.5% 46.6% 46.9% 48.0% 49.8% 50.5% 51.5% Common Equity Ratio 54.0%
Pension Assets-12/17 $586.5 mill. 1434.3 1803.9 1916.4 1797.1 2020.7 2215.7 3168.0 3408.6 3493.9 3614.5 3775 3840 Total Capital ($mill) 4050 Oblig $696.8 mill. 1839.7 1964.1 2118.0 2213.3 2435.6 2690.1 3758.0 4059.5 4214.9 4358.3 4465 4620 Net Plant ($mill) 4975 Pfd Stock None 7.0% 6.0% 5.9% 7.0% 5.5% 5.5% 4.8% 5.2% 5.9% 5.6% 5.5% 5.5% Return on Total Cap'I 6.0%
Common Stock 49,397, 196 shs. 8.9% 9.3% 9.4% 10.8% 9.0% 9.1% 8.2% 8.6% 9.8% 9.0% 9.0% 9.0% Return on Shr. Equity 9.5%
as of 2/9/18 8.9% 9.3% 9.4% 10.8% 9.0% 9.1% 8.2% 8.6% 9.8% 9.0% 9.0% 9.0% Return on Com Equity E 9.5%.
MARKET CAP: $2.7 billion (Mid Cap) 2.3% 3.2% 3.5% 4.7% 3.2% 3.5% 3.8% 3.0% 4.1% 3.4% 3.5% 3.5% Retained to Com Eq 3.5%
ELECTRIC OPERATING STATISTICS 74% 66% 63% 56% 65% 61% 54% 65% 58% 62% 64% 64% All Div'ds to Net Prof 64%
2015 2016 ~i~1-B-U-SI-NLES_S_:_N_oLrth_W_e_s-te~rn-C-o-rp-o~ra-ti-on-(d~oi-ng-bu_sLin-~-s-a_sLN-ort_h__-'-5-%_;_0-thLer-,-4°-Vo.-GLe-n-er_a_tinLg-s_o_ur-ceLs-:h-y-d-ro-,3-6-%-;-co-a-l,-2-9°~V.-;w-i-nd-,~
%Change Relai1Sales([(V,\j) -.1 -.7 Avg. lndust. Use (MWHI 30133 29784 30987 Western Energy) supplies electricity & gas in the Upper Midwest 6%; other, 4%; purchased, 25%. Fuel costs: 31% of revenues. '17 Avg. lndust. Revs.Jer i(IMl 111 NA NA NA and Northwest, serving 433,000 electric customers in Montana and reported deprec. rate: 3.0%. Has 1,600 employees. Chairman:
Capacity at Peak (Mw) NA NA NA South Dakota and 286,000 gas customers in Montana (87% of Stephen P. Adik. President & CEO: Robert C. Rowe. Inc.: Dela-Peakload,Wnler(Mil) 2096 2138 Annual Load Factor(%) NA NA 21Jl gross margin), South Dakota (12%), and Nebraska (1%). Electric ware. Address: 3010 West 69th Street, Sioux Falls, South Dakota
%Change Customers ~1-nd) +1.3 +1.2 +1.3 revenue breakdown: residential, 40%; commercial, 51%; industrial, 57108. Tel.: 605-978-2900. Internet: www.northwesternenergy.com.
F~ed ChargeCov. (%) 252 253 275 We estimate that NorthWestern's wholesale customers (versus the compa-earnings will advance moderately this ny's request for a 20% allocation). This ANNUAL RATES Past Past Est'd '15-'17 of change (per sh) 10Yrs. 5Yrs. ID '21-'23 year. In 2018, the company will benefit forced NorthWestern to take a $0.12-a-Revenues -2.0% -3.0% 2.0% from a full year's effect of a $5.1 million share charge in 2012. Management is "Cash Flow" 5.5% 5.0% 4.0% gas rate hike that took effect in Montana deciding whether pursuing this matter Earnings 8.0% 7.0% 3.5% last September. The refinancing of debt in further is worthwhile.
Dividends 5.5% 7.0% 4.5%
Book Value 5.5% 8.0% 3.5% the fourth quarter of 2017 is another: plus. Another legal matter is pending. The Cal- QUARTERLY REVENUES($ mill.) Full However, there will be some dilution from Montana commission disallowed recovery endar Mar.31 Jun.JO Sep.JO Dec.31 Year the equity issued in 2017 and 2018 via its of certain costs associated with a plant 2015 346 _0 270 _6 272 .7 325 _0 1214_3 at-the-market program. Our 2018 share- outage in 2013. This forced NorthWestern 2016 332.5 293.1 301 _0 330 _6 1257 _2 earnings estimate, which we trimmed by to take a $0.13-a-share charge in the 2016.
2017 367.3 283.9 309.9 344.6 1305.7 $0.05 a share, is within NorthWestern's The utility is seeking relief in the Montana 2018 365 300 315 340 1320 targeted range of $3.35-$3.50. District Court. It expects a decision within 2019 375 310 325 350 1360 An electric rate case is upcoming in the next 12 months.
1--C-al---+---EA-R-NI-NG_S_P_E_R-SH-A-RE-A--1--F-u~II Montana. The utility expects to file an ap- The board of directors raised the divi-endar Mar.31 Jun.JO Sep.JO Dec.31 Year plication by September, with an order due dend in the first quarter. The hike was
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2017 1.17 .44 .75 .98 3.34 ever, regulation in. Montana has worsened payout ratio in a range of 60%-70%.
2018 1.15 .45 .80 1.05 3.45 in recent years, which is a cause for con- This stock has a dividend yield and 3-2019 1.20 .45 .85 1.05 3.55 cern. Still, a partial year of rate relief to 5-year total return potential that t--C-al---+-Q-U-AR_TE_R_t:_Y_DIV-I-DE-N-DS_P_A_ID_B_*_t-t--F-ul~I would benefit earnings in 2019. are above the utility average. This fol-endar Mar.31 Jun.30 Seo.JO Dec.31 Year NorthWestern had a setback in the lows a price decline of more than 10%
1-2-0-14-+==0~=~==-=-.a==- --_- i U.S. Court of Appeals. The utility ap- since the start of 2018. This has been a 4 40 40 40 1 60 2015 :48 :48 :48 :48 1_92 pFeadled aEn unfavRorabl e rulinCg froi:n _the bhad ybear for utilityhequities, (mt ht~e _fadlloff 2016 .50 .50 .50 .50 2.00 e era1 nergy egu 1atory omm1ss1on, as een greater t an most m t 1s m us-2017 .525 .525 .525 .525 2.10 which ruled that just 4% of the cost of a try. There isn't a clear reason why.
2018 .55 gas-fired plant could be allocated to Paul E. Debbas, CFA April 27, 2018 (A) Diluted EPS. Exel. gain (loss) on discont. (B) Div'ds historically paid in late Mar., June, on com. eq. in MT in '14 (elec.): 9.8%; in '17 Company's Financial Strength B+
ops.: '05, (6¢); '06, 1¢; nonrec. gains: '12, 39¢ Sept. & Dec.
- Div'd reinvestment plan avail. (gas): 9.55%; in SD in '15: none specified; in Stock's Price Stability 95 net; '15, 27¢. '15 EPS don't add due to round- (C) Incl. defd charges. In '17: $14.42/sh. (D) In NE in '07: 10.4%; earned on avg. com. eq., '17: Price Growth Persistence 85 ing. Next earnings report due late July. mill. (E) Rate base: Net orig. cost. Rate allowed 9.5%. Regulatory Climate: Below Average. Earnings Predictability 85
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained 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 subscriber's own, non-commercial, internal use. No part llilL'Hl1~,,m1,,._.., 1a,:11Ill'lll!III of nmay be reproduced, resold, stored or transmnted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
18-WSEE-328-RTS 0
I--O_G_E_E_N_ER_G_Y_C-,--O_R~P._NY_SE.-----O_GE-r-----'1'-r-~~f_JfT_3_1_.2-,--0.,__l:_no_15_.2_(_i~~-,--l~~;_U:~-+)~_rEi_rr,t_0_.8..,.......JOl.__~_ _4_.6°_Yo_L---_
TIMELINESS 3 Lowered1/l2/lB High:
Low:
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 24.2 34.2 23.4 37.4 32.6 33.1 29.6 Target Price Range 2021 2022 2023 SAFETY 2 Lowered 12/18115 LEGENDS TECHNICAL 4 Raised 3116118 - -~ii~:ci iivi1;1~~!l ~~te ' t - - - + - - - - - , 1 - - - - + - - - - - + - - - - - - - - - - - - - - - - - - - f - 80 BETA .95 (1.00 = Market)
.* , , Relative 2-for-1 SRltt 7/13~rice Strength t--t----+---t----+--.1nr-t-----+---l----+--l----+--t----+--I----+ 60
<'.*TOI* 50 2021-23 PROJECTIONS o~~~~!/ir~a indicates recession ' 1 I----. 40 Ann'ITotal I I _ 111 1111 1, p1 1 111~k.t<.,,, , 1 p.,,,,,i, 1.":"---- --.
1 1 Price Gain Return 1 1
- ' "- 30 High 50 (+_ 60%1 16% .. " ***" 'llili r:.r 25 Low 35 (+10% 8% 1 1 " A'"' 20 111 1 11 1 Insider Decisions 1 ' ' 1il r i,,,1,11 I "~ 15 M J J A S O N D J
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.to Buy to Sell 2Q2D17 3Q2017 4Q2D17 159 202 Hld's(OOD 145860 145781 124353 151 155 155 138 Percent shares traded 18 1 12Jlimitltffiffi 6
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-11.7 7.7 INDEX 10.1 24.2
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2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUELINEPUB.LLCi,1-23 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 11.00 11.31 11.32 11.75 12.50 Revenues per sh 14.75 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 3.23 3.31 3.34 3.60 4.00 "Cash Flow" per sh 4.75
.72 .87 .89 .92 1.23 1.32 1.25 1.33 1.50 1.73 1.79, 1.94 1.98 1.69 1.69 1.92 2.05 2.15 Earnings per sh A 2.50
.67 .67 .67 .67 .67 .68 .70 .71 .73 .76 .80 .85 .95 1.05 1.16 1.27 1.40 1.54 Div'd Decl'd per sh 8
- 1.85 1.49 1.04 1.51 1.65 2.67 3.04 4.01 4.37 4.36 6.48 5.85 4.99 2.86 2.74 3.31 4.13 3.15 3.15 Cap'I Spending per sh 2.75 6.27 6.87 7.14 7.59 8.79 9.16 10.14 10.52 11.73 13.06 14.00 15.30 16.27 16.66 17.24 19.28 19.95 20.55 Book Value per sh c 22.50 157.00 174.80 180.00 181.20 182.40 183.60 187.00 194.00 195.20 196.20 197.60 198.50 199.40 199.70 199.70 199.70 199.70 199.70 Common Shs Outst'g 0 199.70 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 .17.7 17.7 18.3 Botdfig*res are Avg Ann'I P/E Ratio 17.0
.77 .67 .74 .79 .74 .73 .75 .72 .85 .90 .97 .99 .96 .89 .93 .91 Value Une Relative PIE Ratio .95 estln ates 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% 3.5% 3.9% 3.6% Avg Ann'I Div'd Yield 4.3%
CAPITAL STRUCTURE as of 12/31/17 4070.7 2869.7 3716.9 3915.9 3671.2 2867.7 2453.1 2196.9 2259.2 2261.1 2350 2500 Revenues ($mill) 2950 Total Debt $3168.1 mill. Due in 5 Yrs $668.9 mill. 231.4 258.3 295.3 342.9 355.0 387.6 395.8 337.6 338.2 384.3 410 430 Net Profit ($mill) 500 LT Debt $2749.6 mill. LT Interest $140.4 mill. 30.4% 31.7% 34.9% 30.7% 26.0% 24.9% 30.4% 29.2% 30.5% 32.5% 14.0% 14.0% Income Tax Rate 14.0%
(LT interest earned: 4.3x) 1.7% 9.1% 5.7% 9.0% 2.7% 2.6% 1.7% 3.7% 6.4% 15.0% 8.0% 7.0% AFUDC %to Net Profit 3.0%
Leases, Uncapitalized Annual rentals $4.8 mill. 53.3% 50.6% 50.8% 51.6% 50.7% 43.1% 45.9% 44.3% 41.1% 41.7% 43.0% 44.0% Long-Term Debt Ratio 45.5%
46.7% 49.4% 49.2% 48.4% 49.3% 56.9% 54.1% 55.7% 58.9% 58.3% 57.0% 56.0% Common Equity Ratio 54.5%
Pension Assets-12/17 $635.3 mill. 4058.6 4129.7 4652.5 5300.4 5615.8 5337.2 5999.7 5971.6 5849.6 6600.7 6980 7350 Total Capital ($mill) 8225 Oblig $687.5 mill. 5249.8 5911.6 6464.4 7474.0 8344.8 6672.8 6979.9 7322.4 7696.2 8339.9 8660 8910 Net Plant ($mill) 9450 Pfd Stock None 7.0% 7.9% 7.8% 7.8% 7.7% 8.6% 7.8% 6.9% 7.0% 7.0% 7.0% 7.0% Return on Total Cap'I 7.5%
Common Stock 199,706,104 shs. 12.2% 12.7% 12.9% 13.4% 12.8% 12.8% 12.2% 10.2% 9.8% 10.0% 10.0% 10.5% Return on Shr. Equity 11.0%
as of 1/31/18 12.2% 12.7% 12.9% 13.4% 12.8% 12.8% 12.2% 10.2% 9.8% 10.0% 10.0% 10.5% Return on Com Equity E 11.0%
MARKET CAP: $6.2 billion (Large Cap) 5.4% 6.0% 6.7% 7.7% 7.2% 7.3% 6.5% 4.0% 3.3% 3.5% 3.0% 3.0% Retained to Com Eq 3.0%
ELECTRIC OPERATING STATISTICS 55% 53% 48% 43% 44% 43% 47% 61% 67% 64% 68% 72% All Div'ds to Net Prof 74%
2015 2016 2017 1 - - - - ' - - - - - - ' - - - ' - - - - - ' - - - ' - - - - - ' - - - - - ' - - , - - ' - - - - - ' - - - ' - - - - - ' - - - . . . . . J . - - - - - - - - ' - - - - - - l
%ChangeRetai1Sales(KWtl) -2.9 -1.1 -2.2 BUSINESS: OGE Energy Corp. is a holding company for Oklaho- ing sources: coal, 34%; gas, 25%; wind, 4%; purchased, 37%. Fuel Avg. lndust. Use (MWHl 754 NA NA ma Gas and Electric Company (OG&E), which supplies electricity to costs: 40% of revenues. '17 reported depreciation rate (utility):
Avg.lndust.RevsjlerKWtl(¢) 5.05 5.17 5.30 842,000 customers in Oklahoma (84% of electric revenues) and 2.5%. Has 2,400 employees. Chairman, President and Chief Exec-
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~~
65
~~ NA western Arkansas (8%); wholesale is (8%). Owns 25.7% of Enable utive Officer: Sean Trauschke. Incorporated: Oklahoma. Address:
Annual Load Factor(%) NA NA 6~ Midstream Partners. Electric revenue qreakdown: residential, 40%; 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-
_%_Ch_an_ge_cus1_o_me_rs_1Y_r-e_n~___+_1_.2__+_1_.1__+_1_.o 1-co_m_m_e_rc_ia_1,_2_6'_Vo;_i_nd_u_st_ria..;.l,_9_%..;.;_oi_lfi_el..;.d,_7_%..:.;_ot_h_er'-,_18_%_._G_e_ne_ra_t-_ _ o3_2_1._T_e_le:....ph_o_ne_:_40_5-_5_5_3-_3o_o_o_.l_nt_ern_et_:www
__.o...:g.:...e._co_m_._ _ _--1 F~edChargeCov.(%) 314 336 315 OGE Energy's utility subsidiary has Rate relief should benefit the compa-t-A-N_N_u""'A'-L-RA--'T-'-E-S_P_a-st--P-as-t-Es-t'_d_'1-5_-,1--i7 filed a general rate case in Oklahoma. ny's profits this year and next. Our ofchange(persh) 10Yrs. 5Yrs. to'21-'23 Oklahoma Gas and Electric is asking the 2018 estimate of $2;05 a share is at the Revenues -8.0% -10.0% 4.5% Oklahoma Corporation Commission (OCC) upper end of OGE Energy's targeted range "Cash Flow" 4.0% -.5% 4.5% for an increase of $1.9 million, based on a of $1.90-$2.05. Also, we expect higher Bfv7~i~~~s t~~ tg~ ~:8~ return of 9.9% on a common-equity ratio of equity income from the stake in Enable as Book Value 7.5% 6.5% 4.0% 53%. (The request would have been over the master limited partnership's prospects Cal, QUARTERLY REVENUES ($ mill.) Full
$70 million were it not for the pass- improve.
endar Mar.31 Jun.30 Sep.30 Dec.31 Year through to customers of reduced federal Two environmental compliance taxes.). The utility is seeking to place in projects are on track for completion 2015 480.1 549.9 719.8 447.1 2196.9 2016 433.1 551.4 743.9 530.8 2259.2 the rate base a $390 million project to by yearend. OG&E is adding scrubbers to 2017 456.0 586.4 716.8 501.9 2261.1 modernize the 462-megawatt Mustang two units at the Sooner coal-fired plant at 2018 475 600 750 525 2350 gas-fired plant; restore the depreciation a cost of $542 million. Another coal-fired 2019 500 650 800 550 2500 rates to their level before the OCC cut unit is being converted to a gas-fired facil-Cal- EARNINGS PER SHARE A Full these last year; and raise its allowed ROE ity at cost of $76 million. The utility will endar Mar.31 .Jun.30 Sep.30 Dec.31 Year from the current 9.5%. New tariffs are ex- file a rate application in Oklahoma in late 2015 .22 .44 .88 .15 1.69 pected to take effect at the start of Octo- 2018 in order to place these projects in the 2016 .13 .35 .92 .29 1.69 ber. Note that in Arkansas, OG&E will rate,base .
2017 .18 .52 .92 .30 1.92 recover its investment in Mustang through The dividend yield of this stock is 2018 .20 .50 1.05 .30 2.05 the state's formula rate plan. above the utility average. What's more, 2019 .20 .55 1.10 .30 2.15 The new federal tax law is benefiting OGE Energy expects to hike the disburse-Cal- QUARTERLY DIVIDENDS PAID 8
- Full earnings.. The revaluation of deferred ment by 10% annually through next year.
endar Mar.31 Jun.30 Seo.30 Dec.31 Year taxes produced a nonrecurring gain of Even if the board doesn't maintain such a
$1.18 a share in the fourth quarter of high growth rate beyond 2019, the in-2014 .225 .225 .225 .25 .93 2015 .25 .25 .25 .275 1.03 2017. This year, the lower tax rate applied creases we project should produce a re-2016 .275 .275 .275 .3025 1.13 to OGE Energy's income from its interest spectable total return over the 3- to 5-year 2017 .3025 .3025 .3025 .3325 1.24 in Enable Midstream Partners will add period.
2018 .3325 $0.08 to share net. Paul E. Debbas, CFA March 16, 2018 (A) Oil. EPS. Exel. nonrecur. gain (losses): '02, historically paid in late Jan., Apr., July, & Oct.
- Rate allowed on com. eq_. in OK in '16: 9.5%; in (20¢); '03, (7¢); '04, (3¢); '15, (33¢); '17, $1.18; Div'd reinvestment plan available. (C) Incl. de- AR in '11: 9.95%; earned on avg. com. eq., '17:
I Company's Financial Strength Stock's Price Stability A
85 gains on disc. ops.: '02, 6¢; '05, 25¢; '06, 20¢. !erred charges. In '17: $1.42/sh. (D) In mill., 17.0%. Regulatory Climate: Average. Price Growth Persistence 55 Next earnings report due early May. (8) Div'ds adj. for split. (E) Rate base: Net original cost. Earnings Predictability 80
© 2018 Value Line, Inc. All nghts reserved. Factual material is obtained 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 subscriber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of tt may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
18-WSEE-328-RTS 0
t--P_IN_N_A---::-C_LE_*W_ES---,-T_N_YS~E-_PNW---.-----.---~1---,--~~fc_ErT----r-80_.1--r-5~1:---,-Tlo_1_8'-,-1(_i~--r~/~~-:1~_:0t--~TELA_J~---,--15_0.__,96_,_~_f~-,---3'---,-6°_Yo_ _----i TIMELINESS 4 Lowered 3130118 High: 51.7 42.9 38.0 42.7 48.9 54.7 61.9 71.1 73.3 82.8 92.5 85.6 Target Price Range Low: 36.8 26.3 22.3 32.3 37.3 45.9 51.5 51.2 56.0 62.5 75.8 73.8 2021 2022 2023 SAFETY 1 RaisedS/3/13 -
LEGENDS 0.63 x Dividends p sh 120 100 TECHNICAL 5 Lowered4/6/18 .... i~i~fieb~r/g~e;~~n~~e /".... ,,,, 11 ,, 1 **** * **** ** 80 BETA .65 (1.00 = Marl<et) O~tions: Yes .--- ii" " * ~- * * * * * * * * * * * *
- 64 2021 23
- PROJECTIONS haded area indic~les recession ,t---t-----1-7/4-~ ..-.. ,i,"':,,It;.,;;:;:;;:,,,;:I,: ;,;;;,?,
1 11 ;!'
11 ,'f't;;,1T1 1 J'ttt'-'--t---=~~-.-:.:-:.::.j_;:-:_:--_ -t----t--t----t-48 Ann'I Total ,. 1,, I 1, 1 , ,,-;;,,,, 11 Price Gain Return "" II*' I 1.i.-.r:::;, I .,,, 1*'111' 1 High 90 (+10%1 7% **** 32 Low 75 (-5% 3% *..:__ --:-... *1 *** . . .II l,,1!. .... ******* * .* 24 1 1 *** ** * ***.. 20 Insider Decisions **** * ****** ... * ****.*** * *-**** ****
J J A S O N D J F I I 16 to Buy o o o o o o o o o I I 12 Options o o o o 12 o o 112 to Sell o o 3 o o 2 1 1 o I j
% TOT. RETURN 1 9 _
31 8 I j
'1111 Institutional Decisions THIS VLARITH."
2Q2017 3Q2017 4Q2017 Percent 30 STOCK INDEX ,..
lo Buy toSell 194 224 Hld's(OOO 107032 104825 94333 218
- 182 shares 185 183 traded 20 10 I 11 1,1 ,. ..,
1111111111 1111111111 111111111 1111111111 111111111111 IIII 1111 "" It tltftltrttlh\-;tffi ...litTtr.ttt--t---13yr.
1 yr. -1.2 39.0 9.7 _
24.3 _
.l!:IIIL!!111~11111Llf.l!:111~1111~11,IL.lf.l!:ll,.,,..,.-=-+-:-:::-:-:-+-5-,i;y,:,r.,;.,.,,=65,-;.3==-:::=6-,-8..,. ,8::-r:17"::-=-i 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUELINEPUB.LLC1<1-23 28.90 30.87 31.59 30.16 34.03 35.07 33.37 32.50 30.01 29.67 30.09 31.35 31.58 31.50 31.42 31.90 32.80 34.30 Revenues per sh 39.75 7.01 7.33. 6.93 5.76 9.70 9.29 8.13 8.08 6.85 7.52 7.92 8.15 8.09 9.09 9.. 39 9.79 10.10 10.65 "CashFlow"persh 12.75 2.53 2.52 2.58 2.24 3.17 2.96 2.12 2.26 3.08 2.99 3.50 3.66 3.58 3.92 3.95 4.43 4.50 4.70 Earnings per sh A 5.50 1.63 1.73 1.83 1.93 2.03 2.10 2.10 2.10 2.10 2.10 2.67 2.23 2.33 2.44 2.56 2.70 2.86 3.02 Div'd Decl'd per sh 8
- 3.50 9.81 7.60 5.86 6.39 7.59 9.37 9.46 7.64 7.03 8.26 8.24 9.36 8.38 9.84 11.64 12.80 11.25 10.80 Cap'l Spending per sh 11.00 29.44 31.00 32.14 34.57 34.48 35.15 34.16 32.69 33.86 34.98 36.20 38.07 39.50 41.30 43.15 44.80 46.35 48.00 Book Value per sh c 54.00 91.26 91.29 91.79 99.08 99.96 100.49 100.89 101.43 108.77 109.25 109.74 110.18 110.57 110.98 111.34 111.75 112.00 112.25 Common Shs Outst'g O 113.00 14.4 14.0 15.8 19.2 13.7 14.9 16.1 13.7 12.6 14.6 14.3 15.3 15.9 16.0 18.7 19.3 Bold fig res are Avg Ann'l P/E Ratio 15.0
.79 .80 .83 1.02 .74 .79 .97 .91 .80 .92 .91 .86 .84 .81 .98 .97 Value Une Relative P/E Ratio .85 4.5% 4.9% 4.5% 4.5% 4.7% 4.8% 6.2% 6.8% 5.4% 4.8% 5.3% 4.0% 4.1% 3.9% 3.5% 3.2% estln ates Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUCTURE as of 12/31/17 3367.1 3297.1 3263.6 3241.4 3301.8 3454.6 3491.6 3495.4 3498.7 3565.3 3675 3850 Revenues ($mill) 4500 Total Debt $4829.4 mill. Due in 5 Yrs $1188.4 mill. 213.6 229.2 330.4 328.2 387.4 406.1 397.6 437.3 442.0 497.8 505 535 Net Profit {$mill) 630 LT Debt $4789.7 mill. LT Interest $213.6 mill. 23.4% 36.9% 31.9% 34.0% 36.2% 34.4% 34.2% 34.3% 33.9% ~2.5% 18.0% 18.0% Income Tax Rate 18.0%
Incl. $13.4 mill. Palo Verde sale leaseback lessor 14.1% 13.9% 13.0% 10.0% AFUDC %to Net Profit 8.0%
17.5% 11.2% 11.7% 12.8% 9.7% 10.0% 11.6% 11.8%
notes.
(LT interest earned: 4.4x) 46.8% 50.4% 45.3% 44.1% 44.6% 40.0% 41.0% 43.0% 45.6% 48.9% 48.0% 48.5% Long-Tenn Debt Ratio 45.5%
Leases, Uncapitalized Annual rentals $13.4 mill. 53.2% 49.6% 54.7% 55.9% 55.4% 60.0% 59.0% 57.0% 54.4% 51.1% 52.0% 51.5% Common Equity Ratio 54.5%
Pension Assets-12/17 $3057.0 mill. 6477.6 6686.6 6729.1 6840.9 7171.9 6990.9 7398.7 8046.3 8825.4 9796.4 9985 10480 Total Capital ($mill) 11175 Oblig $3394.2 mill. 8916.7 9257.8 9578.8 9962.3 10396 10889 11194 11809 12714 13445 14075 14625 Net Plant ($mill) 16125 Pfd Stock None 6.1% 6.0% 6.0% Return on Total Cap'I 6.5%
4.7% 4.8% 6.5% 6.4% 6.8% 7.1% 6.4% 6.4% 6.0%
Common Stock 111,799,789 shs. 6.2% 6.9% 9.0% 8.6% 9.8% 9.7% 9.1% 9.5% 9.2% 9.9% 10.0% 10.0% Return on Shr. Equity 10.5%
as of 2/16/18 6.2% 6.9% 9.0% 8.6% 9.8% 9.7% 9.1% 9.5% 9.2% 9.9% 10.0% 10.0% Return on Com Equity E 10.5%
MARKET CAP: $9.0 billion (Large Cap) .3% .7% 3.1% 2.8% 4.1% 4.1% 3.5% 3.9% 3.5% 4.2% 3.5% 3.5% Retained to Com Eq 4.0%
ELECTRIC OPERATING STATISTICS 96% 89% 66% 68% 58% 58% 62% 59% 62% 58% 63% 63% All Div'ds to Net Prof 63%
. 2015 2016 2017 1---~-~--~-~-- ~-~-~--~-~-~- -~-~------~--1
%ChangeRetai1Sales[K'Mi) +1.3 +.3 ** BUSINESS: Pinnacle West Capital Corporation is a holding compa- commercial, 40%; industrial, 5%; other, 5%. Generating sources:
Avg. lnlfusl. Use (Ml'IH) 658 640 620 ny for Arizona Public Service Company (APS), which supplies elec- nuclear, 29%; gas & other, 26%; coal, 22%; purchased, 23%. Fuel Avg.lndusl.Revs._p_eriMII(/) 8.17 8.37 8.34 tricity to 1.2 million customers in most of Arizona, except about half costs: 28% of revenues. '17 reported deprec. rate: 2.8%. Has 6,300 Capaci~a!Peak(Mwl 9250 9192 8438 of the Phoenix metro area, the Tucson metro area, and Mohave employees. Chairman, President & CEO: Donald E. Brandt. Inc.:
Peak load, Surnmer(Mll) 7031 7051 7363 AnnualloadFactor(o/o) 48.3 48.0 46.3 County in northwestern Arizona. Discontinued Suncor real estate AZ. Address: 400 North Fifth St., P.O. Box 53999, Phoenix, AZ
%ChangeCustomers(yr-end) +1.3 +1.3 +1.8 subsidiary in '10. Electric revenue breakdown: residential, 50%; 85072-3999. Tel.: 602-250-1000. lnternet:.www.pinnaclewest.com.
foedChargeCov.(%) 438 416 425 Pinnacle West's utility subsidiary has crease this year. Pinnacle West raised ANNUAL RATES Past Past Est'd ,15 ., 17 asked the Arizona Corporation Colll- its 2018 earnings guidance by a dime a ofchange(persh) 10Yrs. 5Yrs. to'21-'23 Dlission for a rate increase. Although share, to $4.35-$4.55, due largely because Revenues -.5% 1.0% 4.0% the rate order last year for Arizona Public the company raised its expectation for the "Cash Flow" 1.5% 5.0% 5.0% Service froze base tariffs mid-2020, the Allowance for Funds Used During Con-Earnings 4.0% 5.0% 5.0% d A Dividends 2.5% 2.5% s.5% ruling also allowed APS to file for recovery struction, a noncash ere it to income. d-Book Value 2.0% 4.0% 4.0% of an environmental project at the Four ditional expense-management initiatives Cal- QUARTERLY REVENUES($ mill.) Full Comers coal-fired station through a rider are another factor. We raised our estimate endar Mar.31 Jun.30 Sep.30 Dec.31 Year (surcharge) on customers' bills. The utility by $0.10 a share, to $4.50.
2o1 5 671 .2 890.7 1199.1 734.4 3495.4 is seeking an increase of $65 million We forecast higher profit growth in 2016 677.2 915.4 1166.9 739.2 3498.7 (about 2%), and no *change in the allowed 2019. The aforementioned rate rider 2017 677.7 944.6 1183.3 759.7 3565.3 return on equity of 10%. A decision is ex- should help. In addition, the utility's 2018 700 975 1225 775 3675 pected in time for the rider to take effect strong (and rising) customer growth rate is 2019 725 1025 1300 800 3850 at the start of 2019. The project should be stimulating modest kilowatt-hour sales Cal- EARNINGSPERSHAREA Full completed soon at a cost of $390 million. growth, despite the effects of energy ef-endar Mar.31 Jun.30 Sep.30 Dec.31 Year The costs that the company will incur this ficiency. Our $4. 70-a-share earnings es-2015 .14 1.10 2.30 .37 3.92 year will be deferred for recovery begin- timate would produce an increase of 4%.
2016 .04 1.08 2.35 .47 3.95 Anning nhext year unde: talhe rid~r. . d T!1,i sd untdiinely stock has a aldividend 2017 .21 1.49 2.46 .27 4.43 ot er large capit proJect 1s un er yie1 an 3- to 5 -year tot return 2018 .25 1.30 2.60 .35 4.50 construction. APS is building five gas- potential that are about average, by 2019 .25 1.35 2.70 .40 4.70 fired units and retiring two at an esti- utility standards. Perhaps conservative Cal- QUARTERLY DIVIDENDS PAID e
- Full mated cost of $500 million. This will in- investors will find this acceptable, given endar Mar.31 Jun.30 Seo.30 Dec.31 Year crease the utility's generating capacity by the equity's top-notch Safety rank and the
_ 290 megawatts. Costs associated with this company's high rating for Financial 2014 568 568 568 595 2 30 2015 :595 :595 :595 :625 2.41 phroject :Will. be deferrebd until APS _recovers Strengthh. However. li~e n:iohs~ utility is -
2016 .625 .625 .625 .655 2.53 t ese m its next ase rate increase, sues, t e recent pnce 1s wit m our 202 1-2017 .655 .655 .655 .695 2.66 presumably in mid-2020. 2023 Target Price Range.
2018 .695 We estiD1ate a D1odest earnings in- Paul E. Debbas, CFA April 27. 2018 (A) Diluted EPS. Exel. nonrec. gain (losses): '16 EPS don't sum due to rounding. Next earn- avail. (C) Incl. defd chgs. In '17: $14.34/sh. Company's Financial Strength A+
'02, (77¢); '09, ($1.45); '17, 8¢; gains (losses) ings report due early May. (B) Div'ds historical- (D) In mill. (E) Rate base: Fair value. Rate al- Stock's Price Stability 95 from disc. ops.: '05, (36¢); '06, 10¢; '08, 28¢; ly pd. in early Mar., June, Sept., & Dec. There lowed on com. eq. in '17: 10.0%; earned on Price Growth Persistence 70
'09, (13¢); '10, 18¢; '11, 10¢; '12, (5¢). '15 & were 5 declarations in '12.
- Div'd reinv. plan avg. com. eq., '17: 10.0%. Regul. Climate: Avg. Earnings Predictability 95
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed lo be reliable and is provided wnhout warranties of any kind. - ,
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part I I I' ,ll.1!:illl""!lll!:11 of nmay be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
18-WSEE-328-RTS PORTLAND GENERAL NYSE-POR IRECENT PRICE 40 , 92 IPIERATIO 18, . 4Crajling:17.9)
Median: 16.0 RELATIVE PIE RATIO O98 DIV'YLDD 3.5%-"'~*
I TIMELINESS 4 Lowered 3/23/18 High: 31.3 27.7 21.4 22.7 26.0 28.1 33.3 40.3 41.0 45.2 50.1 45.6 Target Price Range Low: 25.5 15.4 13.5 17.5 21.3 24.3 27.4 29.0 33.0 35.3 42.4 39.0 2021 2022 2023 SAFETY 2 Raised 5/4112 -
LEGENDS 0.73 x Dividends p sh TECHNICAL 5 Lowered 4120/18 divided b~ Interest Rate
, . , . Relative rice Strength 80 BETA .65 (1.00 = Market) 60 O~~~~:/ir~a indicates recession 50
- -- ,.,-.r,,,,
,111,111*1 2021-23 PROJECTIONS 40 Ann'I Total I I I **---
_u.or11111l11111**
Price Gain Return / *,
- 111111 I I ,
30 I', .1 l""lllll1i I High 50 (+20°4 9%
1
' 25 I 11111111 Low 35 (-15% 1%
'*' .........,:! F<.,,**'11) 111!1! ,.... ,1 *'
20 Insider Decisions J J A S 0 N D J F to Buy 0 0 0 0 0 0 0 0 0 /
V I I I I""* *.......... ......***** ....******* ****...... ********... ........... *********. ........... 15 10 Options 10 O 010 O 0 0 0 5 i !
toSell O O OO0 0 0 0 1 ~7.5
% TOT. RETURN 3/18 Institutional Decisions 2Q2017 3Q2017 4Q2017 Percent 121 I I I) ., I. 1, I THIS STOCK VLARITH.'
INDEX 1 yr. -6.0 9.7 to Buy to Sell 147 112 122 118 136 shares 91 traded 14 I II
""II@ 1~~1!1~111 ~l!ltl~I I ~~l!l~l l ~~ij~I 1111 Ill 3yr. 19.9 24.3
~
7 5 yr. 55.5 68.8
~
Hld'sfOOD 88988 88359 81125 11111 11111 Ill 2002 2003 2004 2005F 2006 2007 2008 2009 2010 2011 2012 2018 2019 @ VALUE LINE PUB. LLC , 1-23
-- -- -- 23.14 24.32 27.87 27.89 23.99 23.67 24.06 23.89 23.18 24.29 21.38 21.62 22.54 22.70 23.50 Revenues per sh 25.75
-- -- -- 4.75 4.64 5.21 4.71 4.07 4.82 4.96 5.15 4.93 6.08 5.37 5.78 6.16 6.40 6.85 "Cash Flow" per sh 8.00
-- -- -- 1.02 1.14 2.33 1.39 1.31 1.66 1.95 1.87 1.77 2.18 2.04 2.16 2.29 2.20 2.35 Earnings per sh A 2.75
-- -- -- -- .68 .93 .97 1.01 1.04 1.06 1.08 1.10 1.12 1.18 1.26 1.34 1.42 1.50 Div'd Decl'd per sh e
- t 1.80
-- -- -- 4.08 5.94 7.28 6.12 9.25 5.97 3.98 4.01 8.40 12.87 6.73 6.57 5.77 6.35 5.10 Cap'I Spending per sh 5.00
-- -- -- 19.15 19.58 21.05 21.64 20.50 21.14 22.07 22.87 23.30 24.43 25.43 26.35 27.11 27.85 28.70 Book Value per sh c 31.50
-- -- -- 62.50 62.50 62.53 62.58 75.21 75.32 75.36 75.56 78.09 78.23 88.79 88:95 89.11 89.25 89.40 Common Shs Outst'g o 90.00
-- -- -- -- 23.4 11.9 16.3 14.4 12.0 12.4 14.0 16.9 15.3 17.7 19.1 20.0 Bold fig res are Avg Ann'I P/E Ratio 15.5
-- -- -- -- 1.26 .63 .98 .96 .76 .78 .89 .95 .81 .89 1.00 1.01 Value Line estln ates Relative P/E Ratio .85
-- -- -- -- 2.5% 3.3% 4.3% 5.4% 5.2% 4.4% 4.1% 3.7% 3.3% 3.3% 3.1% 2.9% Avg Ann'I Div'd Yield 4.2%
CAPITAL STRUClURE as of 12/31/17 1745.0 1804.0 1783.0 1813.0 1805.0 1810.0 1900.0 1898.0 1923.0 2009.0 2025 2100 Revenues ($mill) 2325 Total Debt $2426 mill. Due In 5 Yrs $460 mill. 87.0 95.0 125.0 147.0 141.0 137.0 175.0 172.0 193.0 204.0 195 210 Net Profit ($mill) 255 LT Debt $2426 mill. LTlnterest $123 mill.
Incl. $49 mill. capitalized leases.
28.7% 28.8% 30.5% 28.3% 31.4% 23.2% 26.0% 20.7% 20.6% 25.3% 12.5% 12.5% Income Tax Rate 12.5%
(LT interest earned: 3.1x) 17.2% 31.6% 17.6% 5.4% 7.1% 14.6% 33.7% 19.8% 16.6% 8.8% 7.0% 5.0% AFU DC %to Net Profit 4.0%
Leases, Uncapitalized Annual rentals $9 mill. 46.2% 50.3% 53.0% 49.6% 47.1% 51.3% 52.7% 47.8% 48.4% 50.1% 47.0% 50.5% Long-Tenn Debt Ratio 48.5%
Pension Assets-12/17 $629 mill. 53.8% 49.7% 47.0% 50.4% 52.9% 48.7% 47.3°,P 52.2% 51.6% 49.9% 53.0% 49.5% Common Equity Ratio 51.5%
Oblig $869 mill. 2518.0 3100.0 3390.0 3298.0 3264.0 3735.0 4037.0 4329.0 4544.0 4842.0 4710 5190 Total Capital ($mill) 5500 Pfd Stock None 3301.0 3858.0 4133.0 4285.0 4392.0 4880.0 5679.0 6012.0 6434.0 6741.0 6930 6985 Net Plant !$mill) 7000 Common Stock 89,114,522 shs. 5.0% 4.5% 5.4% 6.2% 5.9% 5.1% 5.8% 5.4% 5.6% 5.5% 5.5% 5.5% Return on Total Cap'I 6.0%
as of 2/2/18 6.4% 6.2% 7.9% 8.8% 8.2% 7.5% 9.2% 7.6% 8.2% 8.4% 8.0% 8.5% Return on Shr. Equity 9.0%
6.4% 6.2% 7.9% 8.8% 8.2% 7.5% 9.2% 7.6% 8.2% 8.4% 8.0% 8.5% Return on Com Equity E 9.0%
MARKET CAP: $3.6 bi11ion (Mid Cap) 2.0% 1.5% 3.0% 4.1% 3.5% 2.9% 4.6% 3.3% 3.5% 3.6% 3.0% 3.0% Retained to Com Eq 3.5%
ELECTRIC OPERATING STATISTICS 69% 76% 62% 54% 57% 61% 50% 56% 57% -58% 64% 63% All Div'ds to Net Prof 63%
2015 2016 2017 BUSINESS: Portland General Electric Company (PGE) provides
%Cha~e Relail Sales (Kl'lli) +.6 -2.1 +3.9 28%; coal, 15%; wind, 8%; hydro, 8%; purchased, 41%. Fuel costs:
Avg. In ust. Use (MNH~ 17485 16146 16041 electricity to 875,000 customers in 52 cities in a 4,000-square-mile 30% of revenues. '17 reported depreciation rate: 3.6%. Has 2,900 Avg. lndu&. Revsi (¢) 5.01 4.99 4.94 area of Oregon, including Portland and Salem. The company is in employees. Chairman: Jack E. Davis. President and Chief Execu-Capaci~ al Peak ~ 4609 4730 4743 the process of decommissioning the Trojan nuclear plant, which it tive Officer: Maria M. Pope. Incorporated: Oregon. Address: 121 Peak Load, Summer ) 3914 3726 3976 Annu~ load Facior ( */ NA NA NA closed in 1993. Electric revenue breakdown: residential, 48%; com- S.W. Salmon Street, Portland, Oregon 97204. Telephone: 503-464-
%ChangeCuslomers yr-nd) +1.2 +1.2 +1.3 mercial, 33%; industrial, 11 %; other, 8%. Generating sources: gas, 8000. Internet: www.portlandgeneral.com.
F~ed Charge Cov. (%) 243 271 298 Portland General Electric has filed a Unrecovered costs associated with the ANNUAL RATES Past Past Est'd '15-'17 rate case. The utility requested an in- Carty gas-fired plant continue to be a of change (per sh) 10 Yrs. 5Yrs. to '21-'23 crease of $89 million (4.8%), based on a re- drag on earnings. The facility was com-Revenues -1.5% -2.0% 3.0% turn of 9.5% on a common-equity ratio of pleted in 2016, several months after PGE "Cash Flow" 1.5% 3.0% 5.5% 50%. An order from the Oregon Public declared the contractor of the project in Earnings 4.0% 3.5% 4.0%
Dividends 9.0% 3.5% 6.0% Utility Commission (OPUC) is expected in default of the construction agreement.
Book Value 3.0% 3.5% 3.0% December, with new tariffs taking effect at However, $123 million of the plant's $637 Cal- QUARTERLY REVENUES ($ mill.) the start of 2019. million cost are not reflected in rates. PGE Full endar Mar.31 Jun.JO Sep.JO Dec.31 Year Earnings are likely to decline this filed suit against the contractor's insurer, 2015 473.0 450.0 476.0 499.0 1898.0 year. Favorable weather patterns helped seeking to collect a $14 5. 6 million perform-2016 487.0 428.0 484.0 524.0 1923.0 the bottom line in 201 7, but the weather ance bond, plus damages. The company ex-2017 530.0 449.0 515.0 515.0 2009.0 in early 2018 turned the other way. In pects resolution of this matter to take two 2018 530 455 515 525 2025 fact, the Portland area had its second- to four years, but was citing the same time 2019 555 470 530 545 2100 warmest January on record. We have frame two years ago. Unrecovered costs Cal- EARNINGS PER SHARE A Full lowered our *earnings estimate by $0.20 a and litigation expenses reduced earnings endar Mar.31 Jun.JO Sep.JO Dec.31 Year share, to $2.20. Our revised estimate is by $0.09 a share in 2017, and the loss will 2015 .62 .44 .40 .57 2.04 within PGE's guidance of $2.10-$2.25 a widen to an estimated $0.12 a share this 2016 .68 .42 .38 .68 2.16 share. year due to the lower tax shield from the 2017 .82 .36 .44 .67 2.29 There is a possible risk to earnings reduced federal tax rate.
2018 .70 .42 .43 .65 2.20 this year. PGE is going to ask the OPUC We forecast an earnings recovery in 2019 .75 .45 .45 .70 2.35 for permission to defer (for future 2019. We assume normal weather condi-Cal- QUARTERLY DIVIDENDS PAID e
- t Full recovery) costs in 2018 associated with the tions and reasonable treatment in the endar Mar.31 Jun.JO Seo.JO Dec.31 Year upgraded customer information system the aforementioned rate case.
2014 .275 .275 .28 .28 1.11 company expects to complete soon. If the This unti..m.ely stock has a dividend 2015 .28 .28 .30 .30 1.16 OPUC doesn't approve this request and yield and 3- to 5-year total return 2016 .30 .30 .32 .32 1.24 the utility must incur these costs, this potential that are about average for a 2017 .32 .32 .34 .34 1.32 would reduce earnings by $0.10 a share utility.
2018 .34 .34 this year. Paul E. Debbas, CFA April 27, 2018 (A) Diluted EPS. Exel. nonrecurring losses: '13, Div'd reinvestment plan avail. t Shareholder in- 9.5%; earned on avg. com. eq., '17: 8.5%. Company's Financial Strength B++
42¢; '17, 19¢. '15 EPS don't sum due to round- vestment plan avail. (C) Incl. deferred charges. Regulatory Climate: Average. (F) '05 per-share Stock's Price Stability 95 ing. Next earnings report due late July. In '17: $4.92/sh. (D) In mill. (E) Rate base: Net data are pro forma, based on shs. outstanding Price Growth Persistence 65 (8) Div'ds paid mid-Jan., Apr., July, and Oct.
- orig. cost. Rate allowed on com. eq. in '18: when stock began trading in '06. Earnings Predictability 80
© 2018 Value Line, Inc. All nghts reserved. Factual matenal ,s obtained from sources believed to be reliable and is provided wnhout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANX ERRO_RS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial,.intemal_use. No part To subscribe call 1-800-VALUELINE of nmay be reproduced, resold, stored or transmrtted many printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
18-WSEE-328-RTS 1--X_C_E_L-EN_E_R_G_Y_N_oo_-x---,--EL_,----,---__._l~~~rit_T---r-4_5._&1,.........l_~'Ir---,--,0_1s_.s_(_i~~---,--
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>----"L=ow~:~~19_.6~~15~-~3..........16.0 19.8 21.2 25.8 26.8 27.3 31.8 35.2 40.0 41.5 2021 2022 2023 SAFETY 1 Raised 5/1/15 LEGENDS TECHNICAL 5 Lowered 4/27/18
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5.6 l-:2=0:-=0"='2'r-2=0=-=0=3-r-=20=0"""4"T":'2o""o"=s--2=oo=s,..,..,2=0=07-200s 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 ©VALUELINEPUB.LLC,, 1-23 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 21.72 21.90 22.46 22.55 22.90 Revenues per sh 25.25 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 4.56 5.04 5.47 5.90 6.15 "Cash Flow" per sh 7.25
.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 2.10 2.21 2.30 2.45 2.55 Earnings per sh A 3.00 1.13 .75 .81 .85 .88 .91 .94 .97 1.00 1.03 1.07 1.11 1.20 1.28 1.36 1.44 1.52 1.60 Div'dDecl'dpersh 8
- 1.90 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 7.26 6.42 6.54 8.25 7.95 Cap'I Spending per sh 6.75 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 20.89 21.73 22.56 23.55 24.85 Book Value per sh c 28.00 398.71 398.96 400.46 403.39 407.30 428.78 453.79 457.51 482.33 486.49 487.96 497.97 505.73 507.54 507.22 507.76 509.50 518.00 Common Shs Outst'g O 522.50 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 16.5 18.5 20.2 Bold fig res are Avg Ann'I P/E Ratio 16.0 NMF .66 .72 .82 .80 .89 .82 .85 .90 .89 .94 .84 .81 .83 .97 1.02 Value Uno Relative PIE Ratio .90 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% 3.7% 3.3% 3.1% estin ates Avg Ann'I Oiv'd Yield 4.0%
CAPITAL STRUClURE as of 12/31/17 11203 9644.3 10311 10655 10128 10915 11686 11024 11107 11404 11500 11850 Revenues ($mill) 13250 Total Debt $15791 mill. Due in 5 Yrs $4262 mill. 645.7 685.5 727.0 841.4 905.2 948.2 1021.3 1063.6 1123.4 1171.0 1240 1320 Net Profit ($mill) 1575 LT Debt $14520 mill. LT Interest $646 mill. 34.4% 35.1% 37.5% 35.8% 33.2% 33.8% 33.9% 35.8% 34.1% 30.7% 9.0% 9.0% Income Tax Rate 9.0%
Incl. $151 mill. capitalized leases. AFUDC %to Net Profit 7.0%
(LT interest earned: 3.5x) 15.9% 16.8% 11.7% 9.4% 10.8% 13.4% 12.5% 7.7% 7.8% 9.4% 11.0% 10.0%
52.2% 51.6% 53.1% 51.1% 53.3% 53.3% 53.0% 54.1% 56.3% 55.9% 58.0% 57.0% Long-Term Debt Ratio 58.0%
Leases, Uncapitalized Annual rentals $238 mill. 47.1% 47.7% 46.3% 48.9% 46.7% 46.7% 47.0% 45.9% 43.7% 44.1% 42.0% 43.0% Common Equity Ratio 42.0%
Pension Assets-12/17 $3088 mill. 14800 15277 17452 17331 19018 20477 21714 23092 25216 25975 28450 29775 Total Capital ($mill) 34800 Oblig $3828 mill. 17689 18508 20663 22353 23809 26122 28757 31206 32842 34329 36775 39050 Net Plant ($mill) 42900 Pfd Stock None 5.5% 5.5% Return on Total Cap'I 6.0%
6.0% 6.2% 5.7% 6.5% 6.1% 6.0% 6.0% 5.8% 5.7% 5.8%
Common Stock 508,064,983 shs. 9.1% 9.3% 8.9% 9.9% 10.2% 9.9% 10.0% 10.0% 10.2% 10.2% 10.5% 10.5% Return on Shr. Equity 10.5%
as of 2/19/18 9.2% 9.4% 8.9% 9.9% 10.2% 9.9% 10.0% 10.0% 10.2% 10.2% 10.5% 10.5% Return on Com Equity E 10.5%
MARKET CAP: $23 billion (Large Cap) 3.8% 3:7% 3.6% 4.3% 4.7% 4.5% 4.5% 4.3% 4.0% 3.9% 4.0% 4.0% Retained to Com Eq 4.0%
ELECTRIC OPERATING STATISTICS 59% 61% 59% 56% 54% 54% 55% 57% 61% 62% 62% 62% All Oiv'ds to Net Prof 63%
%ChangeRelai1Sales(1<.'Mi) 2015
-.6 2016
+.3 20 !~ 1--8-US_I_N... ES_S_:_X_c... el_E_n_e_rg,_y_ln_c___is..._th_e_p_a... br-e-ak-d-ow_n_:-re-si-de_n_tia...l,-3-1_%_;~
re-nt-of_N,_o_rt_he_r_n...S-ta-te-s--'--m-i-ll.-e-le,_ci_ric-,-1.-9...m-il-1.-ga_s,_.-E-le-c.-re,_v___
large C&I Use (Ml',li) 23521 22519 22642 Power, which supplies electricity to Minnesota, Wisconsin, North sm. comm'I & ind'I, 36%; lg. comm'! & ind'I, 18%; other, 15%. Gen-large C&I Revs. per KWH (II 6.10 6.17 6.36 Dakota, South Dakota & Michigan & gas to Minnesota, Wisconsin, erating sources not available. Fuel costs: 40% of revs. '17 reported Capaci~ al Peak (Mwl NA NA NA North Dakota & Michigan; Public Service of Colorado, which sup- depr. rate: 3.1 %. Has 11,500 employees. Chairman, Pres. & CEO:
Peak Load, Summer (Mw)
Annual Load Factor(%)
19583 20423 195 NA NA Jl
+.9 plies electricity & gas to Colorado; & Southweslern Public Service, Ben Fowke. Inc.: MN. Address: 414 Nicollet Mall, Minneapolis, MN which supplies electricity to Texas & New Mexico. Customers: 3.6 55401. Tel.: 612-330-5500. Internet: www.xcelenergy.com.
%ChangeCuslomers(yr-end) +.9 +.9 F~edChargeCov.(%) 358 342 330 Xcel Energy is awaiting orders on rate 2019. Xcel's goal for long-term earnings 1-A-N_N_U_,A,.._L_RA_T'--'E'-S-P_a_s_t--P-as-t-Es-t-'d-,1 - -.,--i cases in three states. The largest ones growth is 5%-6% annually.
5 17 of change (per sh) 10 Yrs. svrs. to *21.123 are Public Service of Colora<;lo's multiyear Xcel's utilities have some proposals Revenues -1.0% .5% 2.5% electric and gas applications. The utility pending involving renewable energy.
"Cash Flow" 4.0% 6.0% 6.5% requested electric hikes totaling $245 mil- The aim is. to retire coal-fired units and re-Earnings 5.5% 5.0%
- 5.5%
Dividends 4.5% 5.5% 5.5% lion from 2018 through 2020, and gas in- place them with renewables, gas, and Book Value 4.5% 4.5% 4.5% creases totaling $139 million over that storage - and to do this without raising span. Each filing is based on a 10% return rates for customers. SPS received approval Cal- QUARTERLY REVENUES 1$ mill.) Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year on a 55.25% common-equity ratio. An in- in New Mexico, and awaits a decision in terim gas increase of $63 million took ef- Texas, for a $1.6 billion project to add 2015 2962 2515 2901 2646 11024 wind in the two states. P.S. of Colorado ex-2016 2772 2500 3040 2795 11107 feet at the start of 2018, and the company 2017 2946 2645 3017 2796 11404 is asking for" a $75 million interim gas pects a ruling in July on its plan to spend 2018 2900 2650 3050 2900 11500 raise at the start of June. Southwestern up to $1.5 billion to add wind, solar, and 2019 3000 2700 3150 3000 11850 Public Service asked the regulators in gas.
EARNINGS PER SHARE A Texas and New Mexico for a total of $97 The board of directors raised the com-Cal- Full endar Mar.31 Jun.30 Sep.30 Dec.31 Year million, based on a 10.25% return on a mon dividend, effective with the April 2.10 58% common-equity ratio. Rulings are ex- payment. The increase was $0.02 a share 2015 .46 .39 .84 .41 (5.6%) quarterly, the same as in recent 2016 .47 .39 .90 .45 2.21 pected this summer in New Mexico and 2017 .47 .45 .97 .42 2.30 early in the fourth quarter {retroactive to years. Xcel's goals for the dividend are 2018 .55 .45 1.00 .45 2.45 January of 2018) in Texas. growth of 5%-7% annually and a payout 2019 .58 .47 1.03 .47 2.55 Rate relief is boosting Xcel's earning ratio of 60%-70%.
QUARTERLY DIVIDENDS PAID e
- power and enabling the company to This untimely stock has a dividend Cal- Full endar Mar.31 Jun.30 Seo.30 Dec.31 Year reduce the gap between its earned yield and 3- to 5-year total return and allowed returns on equity. Man- potential that are about average, by 2014 .28 .30 .30 .30 1.18 utility standards. This might be. accept-2015 .30 .32 .32 .32 1.26 agement's earnings guidance for 2018 is 2016 .32 .34 .34 .34 1.34 $2.37-$2.47 a share. Our estimate of $2.45 able for conservative accounts, given the 2017 .34 .36 .36 .36 1.42 is near the upper end of this range. We issue's top rank for Safety.
2018 .36 .38 forecast more-modest profit growth in Paul E. Debbas, CFA April 27, 2018 (A) Diluted EPS. Exel. nonrecurring gain 1¢. '17EPS don't sum due to rounding. Next tangibles. In '17: $5.92/sh. (D) In mill. (E) Rate Company's Financial Strength A+
(losses): '02, ($6.27); '10, 5¢; '15, (16¢); '17, earnings report due early May. (B) Div'ds his- base: Varies. Rate allowed on com. eq. Stock's Price Stability 100 (5¢); gains (losses) on discontinued ops.: '03, lorically paid mid-Jan., Apr., July, and Oct. (blended): 9.6%; earned on avg. com. eq., '17: Price Growth Persistence 55 27¢; '04, (30¢); '05, 3¢; '06, 1¢; '09, (1¢); '10,
- Div'd reinvestment plan available. (C) Incl. in- 10.4%. Regulatory Climate: Average. Earnings Predictability 100
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wnhout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of n may be reproduced, resold, stored or transmnted in any printed, electronic or other form, 01 used for generating or marketing any print*.~ or electronic publication, service or product.
18-WSEE-328-RTS December 15, 2017 ELECTRIC UTILITY (CENTRAL) INDUSTRY 901
, All of the major electric utilities located in the INDUSTRY TIMELINESS: . 63 (of 97) central region of the United States are reviewed in this Issue; eastern electrics, in Issue 1; and' *the have formula rate plans that cover other kinds of spend-remaining utilities, in Issue 11. ing in most of their jurisdictions. The aforementioned gas main replacement by WEC Energjs Chicago utility Electric companies have been disseminating is being recovered through monthly surcharges *on cus-their new long-term *capital spending plans. In tomers' bills.
many cases, the capital budgets are increasing. We discuss where these monies are going. Merger And Acquisition Update
. The roster of companies in the Electric Utility Indus-We provide an update of merger and acquisition try has shrunk in recent years thanks to mergers and activity in the Electric Utility Industry. acquisitions. Pending deals that await regulatory ap-proval include the combination of Great Plains Energy Most equities in this industry have performed and Westar Energy and the takeover of Avista (covered in extremely well in: 2017. The stocks are expensively
- Issue 11). This year, the share prices of several other priced~ utilities have risen sharply due to takeover speculation.
This includes ~ctren. We advise against buying a stock solely because of takeover speculation, however. Even if Rising Capital Budgets a deal is reached, obtaining regulatory approval is often At the Edison Electric Institute Financial Conference, difficult. Many proposed transactions in this industry held annually in November, many electric companies have fallen through, including the first deal between
- unveil their long-term (typically three or five years) Great Plains and Westar. The companies reworked their' capital spending plans: For many utilities, the budget agreement to make it (presumably) amenable to the for the period beginning in 2018 is higher than the one regulators.
for the period that began in 2017. This doesn't necessar-ily mean that capital spending in 2018 will be greater Conclusion than the 2017 figure, only that the expenditures over the In 2017, most electric utility' equities have risen multiyear p~riod will probably exceed those of the pre- sharply in price. Those that have advanced at a mere vious period. ' single-digit pace are the exception, not the rule. There are some exceptions. SCANA (covered in Issue 1) has Where is this spending targeted? .This depends on the plummeted due to the. severe problems with its utility's company. Electric transmission* is a key area of 'invest- nuclear construction* project, which was canceled. The ment for Fortis (the parent company of ITC Holdings, a equities of two California companies, PG&E Corp. and transmission-only utility in the upper Midwest), Ameri~ Edison International (coverec:l in Issue 11). have been can Electric Power, Ameren, and ALLETE. Several com- weak due. to the market's worries about liability for*
panies are adding wind or solar projects to meet their wildfires in the Golden State this year. Otherwise, steep states' renewable-energy requirements. CMS Energy is . price increases have been the norm. Takeover specula-replacing old equipment, some of which dates back tion has buoyed some stocks, and investors continue to before 1970. WEC Energy Group is replaciIJg gas mains reach for yield in a low interest-rate environment.
at its utility that serves Chicago. ~ctren is modernizing its electric system. ~ntergyplans to install an advanced The average dividend yield of stocks in the Electric metering infrastructure and is building gas-fired power Utility Industry is just 3.3%. Seeing yields below 3% is plants to meet the rising demand for electricity in its no longer unusual, and one equity, MGE Energy, has a service area. (By contrast, many utilities are seeing little yield. of just 2%. Seeing a recent quotation above the i;ir no load growth due to energy efficiency measures and upper end of our 2020-2022 Targe_t Price Range is also no t.he slow recovery from the severe 2007-2009 recession.) longer unusual. Although many' of these stocks might
- And OGE Energy is spending money for environmental well continue to perform well in the near term, we advise compliance. long-term investors to exercise qmtion here.
Paul E. Debbas, CFA How will the utilities fund these* projects? *To the extent that internal cash flow is insufficient, most will Ele_ctric Utility rely 9n debt financing. Low interest rates make this kind RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.)
of financing attractive. Some companies, such as Ame- 150 ren, expect to avoid equity isst1ances of any kind. Fortis intends to limit its equity needs to stock that is issued 120 through its dividend reinvestment and other stock .
plans. CMS Energy will raise some stock in this way as well, but will also benefit from the use of tax-loss 90 75
~
/\- . " - v""- l.--1'-
~
carryforwards. DTE Energy and ~ctren will need to issue some equity, however.
60 4'5
'""~
I" ro" """
This capital spending will expand the utilities' rate base, and thus, boost their earning power. The utility 30
- subsidiaries of American Electric Power, CMS Energy, and. DTE Energy will have frequent rate cases to earn a return on its capital expenditures. Companies recover their transmission investment through forward-looking 15 2011 2012 2013 2014 2015 2016 2017 formula rate plans. Entergy and CenterPoint Energy Index: June, 1967 = 100
© 2017 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wnhout warramies of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRQRS OR OMISSIONS HEREIN. This publication is strict~ for subscribers own, non-commercial, imernal use. No part To subscribe call 1-800-VALUELINE of it may be reproduced, resold, stored or transmitted in any printed, electronic or olher fonn, or u_sed for generating or marketing any printed or electronic publication, service or product
18-WSEE-328-RTS March 16, 2018 ELECTRIC UTILITY (CENTRAL) INDUSTRY 901 All of the major electric utilities located in the INDUSTRY TIMELINESS: 13 (of 97) central region of the United States are reviewed in this Issue; eastern electrics, in Issue 1; and the than they are today. However, the decline in profitability remaining utilities, in Issue 11. of these assets has induced several companies to get out of this business. Ameren discontinued its nonregulated We discuss the new federal tax law's effects on operations in 2013. American Electric Power has all but companies in the Electric Utility Industry. completed the transition from a hybrid company to a regulated entity. Entergy is also exiting almost all of its Some companies in this Industry are making a nonregulated activities, although this process will not be transition from a hybrid (utility and nonutility) completed until 2022. This will reduce the business risk company to an entirely regulated entity. that these companies face. Not every company is ceasing its nonutility operations. DTE Energy is retaining them, Mergers and acquisitions are an ongoing theme as they have less risk than nonregulated power genera-in this industry. tion and account for about 20% of corporate profits.
lkctren also has some nonutility operations.
Following a stellar showing in 2017, the prices of most of the stocks in this industry have declined Mergers And Acquisitions so far in 2018. Still, the group isn't cheap.
In recent years, there has been a lot of merger and acquisition activity among electric companies, or with More On The New Federal Tax Law electric utilities buying gas utilities. A few deals are pending. Great Plains Energy and Westar Energy hope to Now that every company in the Electric Utility Indus- complete their combination by mid-2018. Avista (covered try has reported its results for the fourth quarter of in Issue 11) has agreed to be acquired by Hydro One, a 2017, we can say more than we did in the Electric Utility Canadian company. And Sempra Energy (also reviewed (East) report 'in Issue 1 about the effects ,of the new in Issue 11) intends to buy Oncor, an electric transmis-federal tax law on this industry. The lower tax rate sion and distribution utility in Texas.
forced each company to revalue its deferred taxes and record a noncash credit or charge in the fourth quarter of Conclusion 2017. For some companies, such as CenterPoint Energy, DTE Energy, and OGE Energy, this resulted in a large Most electric utility equities performed extremely well gain. On the other hand, charges sent the bottom lines of in 201 7, aided by a strong, broader stock market, the Ameren, CMS Energy, and Entergy into the red for the desire of many investors for high-yielding issues in an period. Note that we have changed the way we are era of low interest rates, and (in some cases) takeover treating these items in our earnings presentations, offers or takeover speculation. Many stock prices didn't which are now.excluded as nonrecurring items. just rise, they advanced more than 10%. This has changed so far in 2018, as electric utility issues have What about the effects of tax reform on earnings and given back some of their gains of last year. We think this cash flow in 2018? For regulated utility operations, there is due partly to reversion to the mean, and partly to is virtually no doubt that the benefit of lower federal investors' trepidation about rising interest rates. Even taxes will be passed through to customers. The only after the price declines, many recent quotation*s are still questions are how, and in which time frame? Many within their 2021-2023 Target Price Range. Thus, most utility parent companies have debt that is held at the stocks in this Industry are not cheap. The average parent level, and the lower tax shield on the interest dividend yield is 3.6%, which is low, by historical stan-expense will have a modest negative effect on profits. dards. Total return potential over the 3- to 5-year period (Fortis says this will hurt its earnings by 3% this year.) isjust 6%.
Companies that have nonutility operations or invest- Paul E. Debbas, CFA ments, such as the equity income that CenterPoint and OGE get from their stakes in Enable Midstream Part-ners, will see a benefit of lower tax rates. Tax reform will reduce cash flow for utilities, however. That's because Electric Utility federal income taxes are mostly or entirely a noncash RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.)
item, while the pass-through to ratepayers means less 150 cash from them. In order to compensate for this, and maintain their credit ratings, some companies are issu- 120 ing common equity. This includes Ameren and Entergy, 90 .
rvv,..._ ~
which have issued little or no equity in recent years. /\. i... -
Other companies, such as WEC Energy Group, do not 75 'J'
~ '-/
need to sell common stock.
From Partly Regulated To Entirely Regulated
- '60 45 Some companies in the Electric Utility Industry are 30 (or were) hybrids. That is, they have nonregulated operations in addition to their regulated utilities. Most notably, several companies own nonregulated generat-ing assets. This was attractive a decade ago, when 15 2012 2013 2014 2015 2016 2017 2018 natural gas (and thus, power) prices were much higher Index: June, 1967 = 100
© 2019 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wihout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strict~ for subscriber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of it may be reproduced, resold, stored or transmitted in any printed, electroruc or other form, or usad for generating or marketing any printed or electronic publication, sarvice or product.
18-WSEE-328-RTS February 16, 2018 ELECTRIC UTILITY (EAST) INDUSTRY 137 All of the major electric utilities located* in the INDUSTRY TIMELINESS: 88 (of 97) eastern region of the United States are reviewed in this Issue; western electrics, in Issue 11; and the will be a bit less lucrative than it would have been had it remaining ~tilities, in Issue 5. been completed on time and on budget, though, and the utility is still assuming construction risk. By contrast, We discuss how tax reform will affect companies SCE&G canceled its project, and the state legislature in the Electric Utility Industry. does not want the utility to continue to collect money from customers for the unsuccessful project. (The com-Several companies covered .in Issue 1 have in- pany believes the state's Base Load Review Act allows it volvement with nuclear power. Two have worries to continue collecting these monies.) Dominion Energy stemming from nuclear construction, and a few agreed to take over SCANA, as long as there is no have nonregulated assets that are threatened by unfavorable regulatory or legislative changes. With the unfavorable market conditions. price of SCANA stock well below the value of Dominion Energjs offer, the market is skeptical that the deal will Most electric utility stocks have retreated in be completed.
price so far in 2018. However, they are still expen- Other companies reviewed in Issue 1 have a different sive, by historical standards. concern: the lack of profitability of their nonregulated nuclear plants. A combination of low gas prices, subsi-dized renewable energy, and weak demand for power has The New Federal Tax Law hurt these assets. Utilities believe current market prices A new federal tax law took effect at the start of 2018. don't recognize the benefits of nuclear generation (fuel For regulated utilities, it is highly likely that all of the diversity and no carbon emissions). So, some companies benefits of a lower tax rate will be passed through to . are seeking subsidies from the states in which their customers. The only questions are when, and how? nuclear units are based, similar to the "zero emissions However, although a one-for-one pass-through will not credits" that were granted by the Illinois legislature and affect reported profits, this will reduce a utility's cash the New York regulators for plants owned by Exelon.
flow. That's because it will receive less cash from its However, this company still has a unit in Pennsylvania customers, but its cash outlays for taxes won't decline that is threatened with a premature closing, and its correspondingly because utilities' tax liabilities aren't facility in New Jersey will be shut in 2018, a year ahead entirely in cash. Some companies are paying no cash of schedule. Some companies are still seeking some kind taxes at all. In addition, as a trade-off for retaining full of subsidy that would allow them to keep their troubled tax deductibility for interest payments on utility issued nuclear plants open: FirstEnergy in Ohio, Public Service 0
debt, utilities are no longer eligible for bonus deprecia- Enterprise Group in New Jersey, and Dominion Energy tion, which was a boon for cash flow. (In some cases, in Connecticut.
interest payments on debt issued at the parent level will be only partially deductible.) The absence of bonus Conclusion 1
depreciation will have a positive effect on a utility's After the stellar performance of most stocks in the rate-base growth, because deferred taxes that are sub- Electric Utility Industry in 2017, share prices of most tracted from the rate base will be lower than they electric companies declined in the first few weeks of otherwise would have been. This should benefit long- 2018. In our view, this is partly due to reversion to the term earnings growth. However, due to the negative mean, and partly due to investors' increased concern effects on cash flow, the credit-rating agencies have about the likelihood of a few interest-rate increases by placed a negative outlook on some electric companies' the Federal Reserve this year. The average dividend creditworthiness. yield for this industry is up to 3.6%. This is above the Of course, not every company covered in the Electric level seen in 2017, but is still low, by historical stan-Utility Industry is entirely regulated. NextEra Energy dards. Moreover, many of these equities continue to and Dominion Energy, which each have significant non- trade within their 3- to 5-year Target Price Range.
utility operations, have stated that the lower federal tax Paul E. Debbas, CFA rate will boost earnings in 2018. Nonregulated entities are not expected to pass the tax savings onto their customers. Electric Utility The decline in federal tax rates meant that companies RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.)
had to revalue their deferred tax balances. For NextEra 150 Energy and Dominion Energy, this resulted in noncash credits that led to profits that were significantly higher 120 than normal in the fourth quarter of 2017. We are 105 90 . _,...,...,
including these credits or charges in our earnings pre-75 _,. .I'\ - . - 'Vh sentation. ~~ '-v 60 Nuclear Worries Georgia Power (a subsidiary of Southern Compan)1 45 and South Carolina Electric & Gas (a subsidiary of SCANA) each have electric utility subsidiaries with 30 nuclear construction projects that experienced signifi-cant delays and cost overruns. However, the future of each project is very much different. Georgia Power has received permission from the state commission to con- 15 2012 2013 2014 2015 2016 2017 2018 tinue construction, despite the problems. The project Index: June, 1967 = 100
© 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reflable and is provided w!hout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strict~ for subscribers own non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of it may be reproduced, resold, stored or lransmitted in any printed, electronic or other form, or used for generating or marketing any prinled or eleclronic publication, service or product.
- 18-WSEE-328-RTS November 17, 2017 ELECTRIC UTILITY (EAST) INDUSTRY 137 All of the major electric utilities located in the INDUSTRY TIMELINESS: 91 (of 97) eastern region of the United States are reviewed in this Issue; western electrics, in Issue 11; and the canceled construction of the project. The utility has come remaining utilities, in Issue 5. under much criticism since then, and although it be-lieves it is entitled to a return on its investment under Most electric utilities covered in Issue 1 have state law, this is in question. Georgia Power, a larger some involvement with nuclear power. We discuss utility with a larger parent company, intends to proceed the latest happenings affecting these companies' with construction. Its plan requires the go-ahead from nuclear plants. Most noteworthy is the divergent the state commission, however. More information on paths that the two nuclear projects in the South- each of these situations is available in our full-page east are taking. reports on Southern Company and SCANA in this Issue.
Most electric utility equities have performed Conclusion well in 2017. We discuss some of the outliers. The Most electric utility stocks have performed very well group remains expensively priced, in our view. in 2017. Price increases of more than 10% are the rule, not the exception. Despite interest-rate increases from Nuclear Update the Federal Reserve (and the expectation of more to Except for AVANGRID, Consolidated Edison, Ever- come), interest rates are still low, by historical stan-source Energy, and PPL Corporation, every electric com- dards, and yields on money-market funds, CDs, and pany covered in this Issue owns nuclear plants-at the savings accounts remain low enough to be unappealing utility level, a nonutility subsidiary, or both. Companies to some income-oriented investors. Electric utility stocks with regulated nuclear plants are in the best position appeal to these accounts thanks to their above-average because these units are not affected by unfavorable dividend yields. Indeed, even at a historically low aver-conditions in the power markets. On the other hand, age yield *of 3.3%, this figure is still more than a many nonutility nuclear plants without power contracts percentage point above the median of all dividend-(i.e., merchant plants) have seen their margins squeezed paying issues under our coverage. Another positive fac-in recent years due to low prices of natural gas, subsi- tor for stock prices is takeover speculation. Several deals dized renewable energy, and weak demand for power. (mostly involving mid-cap utilities) have occurred in Some facilities are even losing money. The most worri- recent years. Most stocks in the Electric Utility Industry some situation of all is the construction of nuclear units, are trading within their 2020-2022 Target Price Range, which has been plagued by significant delays and cost and some are above this range.
overruns. AVANGRID has been one of the top performers this Duke Energy, which has utility-owned plants solely, is year, having risen more than 30%. We think takeover in the most stable situation, although the company took speculation can be credited. Another top performer is a modest charge in the third quarter to write off the costs Avista (covered in Issue 11). The company has accepted it incurred for a possible new unit. NextEra Energy has a takeover offer from a Canadian utility. NextEra Energy both regulated and nonregulated nuclear facilities. Its has seen its stock price rise over 30%, as the company's nonregulated units have not faced severe market prob- solid performance and presence in renewable energy lems, and the company is in a good position. On the other have attracted investors. On the other hand, the price of hand, nonregulated plants owned by Exelon and SCANA stock has plummeted nearly 40% due to the FirstEnergy have been hurt by poor market conditions aforementioned nuclear problems. PG&E Corporation for the past several years, which weakened each compa- (covered in Issue 11) has seen its share price decline ny's earning power to the point where the board decided modestly due to concern that its utility caused or con-to cut the dividend. Dominion Energy and Public Service tributed to recent wildfires in northern California. The Enterprise Group are also experiencing challenges, but price of Westar stock (covered in Issue 5) has fallen these are much less severe. In order to address unfavor- because its revised deal with Great Plains Energy is not able market conditions that do not recognize the envi- as lucrative as the initial transaction that *failed to win rorimental benefits of nuclear plants (no carbon emis- regulatory approval.
- sions), Illinois and New York hav~ enacted laws or Paul. E. Debbas, CFA regulations that provide zero-emissions credits for nuclear facilities. These subsidies should help, although Electric Utility they are not a cure-all. Connecticut just passed a law RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.)
allowing the Millstone plant (owned by Dominion) to bid 150 into markets along with other nonemitting sources of power. So far, Ohio, Pennsylvania, and New Jersey have 120 not passed similar laws. (Exelon has said it will shut the 105 90 ~ .
Three Mile Island plant in Pennsylvania if legislation is ,.J
/'\ - - v"°' .,...,-.1'-
""'-.. ~ "'v 75 ._.
not enacted.) There is also the possibility of changes at ~
the federal level (from the Federal Energy Regulatory 60 Commission) that would be favorable for owners of 45 merchant nuclear plants.
Several years ago, electric utility subsidiaries of Southern Company (Georgia Power) and SCANA (South 30 Carolina Electric & Gas) each started building two units at the site of an existing nuclear plant. These projects had extensive delays and cost overruns that led to the bankruptcy filing of the contractor, Westinghouse. The 15 2011 2012 2013 2014 2015 2016 2017 utilities have moved in different directions. SCE&G Index: June, 1967 = 100 THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber's own, non-commercial, .internal use. No part To subscribe call 1-800-VALUELINE of it may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.
18-WSEE-328-RTS April 27, 2018 ELECTRIC UTILITY (WEST) INDUSTRY 2222 All of the major electric utilities located in the INDUSTRY TIMELINESS: 77 (of 97) western region of the United States are reviewed in this Issue; eastern electrics, in Issue 1; and the
- not been good for North Western. In fact, the company's remaining utilities, in Issue 5. chief executive officer has mentioned this problein in recent conference calls for quarterly earnings. We are From time to time, we discuss regulatory cli- still keeping an eye on Oklahoma for a possible down-mates and provide a list showing each state's grade, since the latest rate orders in the state have been regulatory climate, plus that of the Federal En- disappointing for utilities there. On the other hand, we ergy Regulatory Commission (FERC). continue to consider Illinois and Michigan for possible upgrades.
California is trying to resolve regulatory and legal matters associated with wildfires in the Wildfires In California state. The three California-based companies reviewed in this Issue (PG&E, Edison International, and Sempra En-Most electric utility stocks have lost value so far erg}1 are concerned about adverse legal and regulatory this year. This does not mean that the group is outcomes associated with wildfires in the Golden State.
cheap, however. Pacific Gas and Electric (a subsidiary of PG&E) and Southern California Edison (a subsidiary of Edison International) had wildfires in their service areas in Ranking The Regulators 2017. The companies' stocks fell sharply last year due to Occasionally, The Value Line Investment Survey pres- investors' worries about a possibly huge liability stem-ents its rankings of regulatory climates for most states, ming from the state's inverse condemnation law, which the District of Columbia, and the Federal Energy Regu- holds that utilities may be held liable
- for damages latory Commission (FERC). Each utility (even those in caused by their power lines, even if they followed estab-states that have deregulated the power-generation func- lished inspection and safety procedures. PG&E sus-tion) is still subject to regulatory ove~sight of their pended its common and preferred dividends, too. Also in transmission and distribution operations, Every utility 2017, San Diego Gas & Electric (a subsidiary of Sempra) will need to deal with a regulatory commission at some took a charge for costs associated with a wildfire 10 point to place new plant in the rate base, recover years earlier after the regulators ruled that the utility increased expenses, or make changes in rate design (i.e., may not pass these costs through to their ratepayers.
the levels of rates among customer classes and the The utilities are trying to find a solution to the inverse proportion of customers' bills that comes from fixed condemnation problem through the legislature, the com-monthly charges). mission, and the courts.
A state's regulatory environment is a key factor in our rankings, but is not the only one. The governor, legisla- Conclusion ture, and courts also play a role. For instance, California So far in 2018, most stocks covered in the Electric is dealing with problems associated with a state law that Utility Industry have declined in price_ This is partly can increase a utility's liability for wildfires. (yve discuss due to reversion to the mean, following a stellar perfor-this matter later in this report.) The legislature and mance for most of these equities in 201 7, and partly due governor will likely have a bigger impact on this law to the rise in interest rates (and the market's expecta-than the commission will. tion that these will climb further). Even after the pull-Note that the table below does not include some states back this year, these issues are not cheap. Many are still because we do not cover a utility that serves that state or trading within their 2021-2023 Target Price Range.
because inv~stor-owned utilities have virtually no pres- Since* Issue 11 came out three months ago, we decided ence in the state. These are Nebraska, Nevada, Rhode to change the way we treat credits or charges that most Island, Tennessee, Utah, and Vermont. Washington and utilities took in the fourth period of 2017 for the effects Alaska will probably be removed from the table if the of the new federal tax law. We are now excluding these pending takeover of Avista by Hydro One, a Canadian from our earnings presentations.
company, is completed. Paul E. Debbas, CFA
- Above Average: Alabama, Alaska, Colorado, Georgia, Electric Utility Idaho, Indiana, Massachusetts, Ohio, South Carolina, RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.)
90 rv~ ~
sota, Mississippi, New Hampshire, New Jersey, North 75 .I'\ - - -
Carolina, North Dakota, Oklahoma, Oregon, Pennsylva-nia, South Dakota, Texas, Virginia, Washington, Wyo- 60 ~ ,,,J-J" '../
ming. 45
- Below Average: Arkansas, Connecticut, District of Columbia, Hawaii, Illinois, Maryland, Missouri, Mon- 30 tana, New Mexico, New York, West Virginia.
Since we last ran this table, in July of 2017, we have lowered the regulatory climate of Montana from Average 15 2012 2013 2014 2015 2016 2017 2018 to Below Average. Most recent rulings in the state have Index: June, 1967 = 100
@ 2018 Value Line, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided wihout warranties of any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRO.RS OR OMISSIONS HEREIN. This publ~ation is strictly 'for subscriber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE of it may be reproduced, resold, stored or transmitted in any pnnted, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product
l 8-WSEE-328-RTS January 26, 2018 ELECTRIC UTILITY (WEST) INDUSTRY 2223 All of the major electric utilities located in the INDUSTRY TIMELINESS: 3 (of 97) western region of the United States are reviewed in this Issue; eastern electrics, in Issue 1; and the and liabilities on companies' balance sheets. For those remaining utilities, in Issue 5. that did not arise from the regulated operations, there will be one-time, noncash gains or losses for the fourth We look back at 2017 and look forward to 2018. quarter of 2017. We will include these in our earnings The new year *has brought changes in federal tax presentation. So far, CenterPoint Energy (covered in.
laws. Issue 5) and AVANGRID (covered in Issue 1) have stated that this will be positive, but Sempra Energy and Xcel The potentially high liability for wildfires is Energy will take charges against December-period re-concerning to electric utilities in California. sults. Sempra also expects some negative effects associ-ated with its foreign operations ..
After a strong showing last year, electric utility equities have given back some of their gains in Wildfires In California early 2018. However, they have hardly become In 2017, wildfires in California affected the service cheap. areas of the utilities owned by PG&E Corporation and Edison International. The causes of the fires have not A Look Back At 2017 And A Look Ahead To 2018 yet been determined, but the market is worried that the The year that just ended was a good one for the utilities will be found liable due to the effects their power Electric Utility Industry as a whole. The prices of most lines might have had on the wildfires. Under the state's stocks didn't just rise, they rose more than 10%. Inves- inverse condemnation law, this may occur eveq if the tors continued to "reach for yield" in an environment of company complied with established inspection and low interest rates. Merger and acquisition activity (and safety rules. The possibly huge liability prompted the speculation) also sent share prices higher. Among the board of directors of PG&E to suspend common and standout performers were A vista, which rose 29% be- preferred dividends. (By contrast, the board of Edison cause the company agreed to be acquired. Two utilities International raised the disbursement.) Change$ to covered in Issue 1, AVANGRID and NextEra Energy, these laws might come, but at this point, no bills to advanced over 30%. For the former company, we attri- address this problem have been introduced in the Cali-
.bute this to takeover speculation; for the latter, simply a fornia legislature. And even if the law is changed, there strong performance. is no assurance that this will apply to the wildfires of last year. ,
On the other hand, the prices of a few electric utility equities fell sharply last year. PG&E Corporation and Another question is whether utilities will be allowed Edison International were hurt by the market's worries to pass costs of restoration and repair through to cus-about possibly huge liabilities resulting from wildfires in tomers. Last year, the California regulators ruled that California in 2017. (:,Ne discuss this matter in the next San Diego Gas & Electric (a subsidiary of Sempra) may section.) SCANA (reviewed in Isslie 1) lost 46% of its not do so in connection with a 2007 wildfire. This forced value due to the cancelation of its nuclear construction the company to write off a regulatory asset in the third project, which faced significant delays and cost overruns. quarter of 2017.
These were the exceptions to the rule.
Conclusion Ironically, in early 2018 SCANA stock was the top Although electric utility equities have not performed performer in the industry. The company agreed to a well so far in 2018, their valuations are still high, by takeover by Dominion Energy (also covered in Issue 1). historical standards. The average dividend yield of Otherwise, the new year has seen declines in most stocks in this industry is 3.6%. Moreover, many of these issues. We suspect some investors are locking in profits. issues are still trading within their 2020-2022 Target Perhaps the expectation of rate hikes by the Federal Price Range. Accordingly, the group's average annual Reserve is also weighing on stock prices in this industry. total return potential over that time frame is just 4%.
Paul E. Debbas, CPA This year might well see additional merger and acqui-sition activity. Besides the deals mentioned above, the Electric Utility proposed combination of Great Plains Energy and We- RELATIVE STRENGTH (Ratio of Industry to Value Line Comp.)
star Energy (reviewed. in Issue 5) is expected to be 150 completed in 2018.
120 Changes in federal tax laws require a discussion. Most 90 r V v-., I.../"-,
compaI).ies are still evaluating the effects of the new law, -
and might not make any public statements about it until they release fourth-quarter earnings in February (for most companies). For the regulated utility business, 75 60 45
,,I
- """ ~ 'v whatever benefits the companies receive from lower taxes will be passed through to customers-the only real question is how, and over which time frame. However, 30 some utilities have nonutility siblings under the um-brella of their parent companies, and these should benefit from tax reform. Hawaiian Electric Industries, with its -American Savings Bank subsidiary, is an ex- 15 2011 2012 2013 2014 2015 2016 2017 ample. Another consideration is the deferred tax assets Index: June, 1967 = 1DO
© 2018 Value Lina, Inc. All rights reserved. Factual malenal is obtained from sources believed lo be reliable and is provided w!hout warranties ol any kind.
THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is str~t~ Jar subscnber's own, non-commercial, internal use. No part To subscribe call 1-800-VALUELINE ol it may be reproduced, resold, stored or transmitted in any pnnled, electronic or other lorm, or used Jar generating or marketing any pnnled or electronic publication, service or product
18-WSEE-328-RTS WESTAR ENERGY NYSE-WR IRECENT PRICE 49 , 72 IPIERATIO 20 , 1 erailing:21.9)
Median: 16.0 RElATNE PIE RATIO 105 DN'YLDD 3.2%lill.
I TIMELINESS - Suspended 6/10/16 High: 28.6 25.9 22.3 25.9 29.0 33.0 35.0 43.2 44.0 57.5 57.3 53.3 Target Price Range Low: 22.8 16.0 14.9 20.6 22.6 26.8 28.6 31.7 33.9 40.0 49.2 47.1 2021 2022 2023 SAFETY 2 Raised 4/1105 LEGENDS 120 TECHNICAL - Suspended 6/10/16 - ~ii~:d ~vi1;t~~!sr ~~ta 100
, , , , Relative ~rice Strength 80 BETA .70 (1.00 = Marl<et)
O~~~~!/i!a indicates rec~ssion -...... *-*-** 64 2021-23 PROJECTIONS Price Gain Ann'I Total Return I
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©VALUE LINE PUB. LLC , 1-23 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 17.40 18.07 18.09 18.60 18.95 Revenues per sh 20.70 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 4.26 4.83 4.90 5.30 5.65 "Cash Flow" per sh 6.75 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 2,09 2.43 2.27 2.60 2.80 Earnings per sh A 3.45 1.20 .87 .80 .92 .98 1.08 1.16 1.20 1.24 1.28 1.32 1.36 1.40 1.44 1.52 1.60 1.60 1.68 Div'd Decl'd per sh Bat 1.92 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 4.95 7.67 5.38 6.50 6.75 Cap'I Spending per sh 7.50 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 25.87 26.84 27.50 28.35 29.10 Book Value per sh c 31.60 71.51 72.!!4 86.03 86.84 87.39 95.46 108.31 109.07 112.13 125.70 126.50 128.25 131.69 141.35 141.79 142.09 142.50 143.00 Common Shs Outst'g E 145.00 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 18.5 21.6 23.4 Bold fig res are Avg Ann'I P/E Ratio 15.0
.76 .62 .92 .79 .66 .75 1.02 .99 .83 .93 .85 .79 .81 .93 1.13 1.15 Value Line Relative P/E Ratio .85 85tin ates 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% 3.7% 2.9% 3.0% Avg Ann'I Div'd Yield 3.7%
CAPITAL SlRUCTURE as of 12/31/17 1839.0 1858.2 2056.2 2171.0 2261.5 2370.7 2601.7 2459.2 2562.1 2571.0 2650 2710 Revenues ($mill) 3000 Total Debt $3963.3 mill. Due in 5 Yrs $725 mill. 136.8 141.3 203.9 214.0 275.1 292.5 313.3 291.9 346.6 323.9. 370 400 Net Profit ($mill) 500 LT Debt $3687.6 mill. LT Interest $170.0 mill.
(LT interest earned: 3.Bx) 24.8% 29.4% 29.0% 35.2% 30.9% 33.1% 31.9% 33.5% 33.8% 31.0% 20.0% 20.0% Income Tax Rate 20.0%
.. -- -- -* -* -- -- 10.4% 10.4% 10.0% 10.0% 10.0% AFUDC %to Net Profit 10.0%
Pension Assets 12/17 $719 mill. Oblig. $1.1 bill. 49.8% 53.4% 53.6% 49.5% 51.2% 50_.0% 50.0% 47.5% 47.9% 51.0% 50.0% 50.0% Long-Tenn Debt Ratio 50.0%
49.7% 46.1% 46.0% 50.1% 48.8% 50.0% 50.0% 52.5% 52.1% 49.0% 50.0% 50.0% Common Equity Ratio 50.0%
4400.1 4866.8 5180.9 5531.0 5938.2 6131.1 6596.2 6958.8 7305.8 7595.7 7750 7850 Total Capital ($mill) 8225 Pfd Stock None 5533.5 5771.7 6309.5 6745.4 7335.7 7848.5 8441.5 8793.1 9506.3 9553.8 9700 9800 Net Plant ($mill) 10500 4.2% 5.3%
Common Stock 142,094,275 shs.
' 6.2%
4.4%
6.2%
5.5%