Greg Gordon, CFA
ggordon@isigrp.com
212.653.9000
Jon Cohen
jcohen@isigrp.com
212.653.8997
Power & Utilities
April 26th, 2012
Bill Appicelli
bappicelli@isigrp.com
212.653.8998
Dmitri Pchelintsev
dpchelintsev@isigrp.com
212.653.8999
1
Power & Utilities Comps
Regulated Utilities
Ticker
Company Name
SO
PGN
NST
ED
D
PCG
SRE
WEC
HE
NU
XEL
DTE
DUK
WR
PNW
CMS
NVE
AEP
TE
EIX
Southern Company Inc
Progress Energy Inc
NStar
Consolidated Edison Inc
Dominion Resources Inc
PG&E Corp
Sempra Energy
Wisconsin Energy Corp
Hawaiian Electric Industries, Inc.
Northeast Utilities
Xcel Energy Inc
DTE Energy Co
Duke Energy Corp
Westar Energy Inc
Pinnacle West Capital Corp
CMS Energy Corp
NV Energy
American Electric Power Co Inc
Teco Energy Inc
Edison International
4/24/12
Price
$45.87
$52.24
$47.65
$58.73
$50.81
$43.48
$64.09
$35.84
$26.16
$36.41
$26.71
$55.98
$21.18
$28.26
$48.11
$22.24
$16.16
$38.27
$17.80
$43.10
ISI
Rating
HOLD
SELL
HOLD
SELL
HOLD
BUY
HOLD
HOLD
HOLD
HOLD
HOLD
HOLD
HOLD
BUY
BUY
HOLD
HOLD
HOLD
HOLD
BUY
Shares
Out
863
296
104
294
575
403
242
235
96
178
486
170
1,333
118
110
263
237
482
215
328
Market
Cap
39,607
15,450
4,955
17,286
29,192
17,522
15,483
8,439
2,507
6,472
12,968
9,517
28,222
3,340
5,274
5,855
3,837
18,457
3,831
14,137
Regulated Group Average
Regulated Group Max
Regulated Group Min
2012
Div Yld
2012
Payout
4.3%
4.7%
3.8%
4.1%
4.2%
4.2%
3.7%
3.3%
4.7%
3.5%
4.0%
4.4%
4.8%
4.7%
4.4%
4.3%
3.5%
4.8%
5.0%
3.0%
72%
78%
69%
65%
67%
56%
58%
53%
73%
53%
60%
64%
71%
68%
63%
62%
47%
62%
65%
38%
4.2%
5.0%
3.0%
62%
78%
38%
ISI EPS Estimate
2012
2013
2014
2.70
3.17
2.61
3.75
3.15
3.25
4.15
2.26
1.70
2.40
1.78
3.80
1.43
1.95
3.40
1.55
1.22
3.00
1.38
3.35
2.85
3.27
3.03
3.80
3.30
2.85
4.25
2.38
1.82
2.55
1.90
4.00
1.52
2.05
3.50
1.65
1.24
3.00
1.43
3.50
3.05
3.34
3.22
3.85
3.45
3.35
4.70
2.47
1.95
2.80
2.00
4.20
1.60
2.15
3.60
1.76
1.30
3.30
1.48
3.60
2012
P/E Multiple
2013
2014
'11-'15
EPS Growth
Price to
Book
17.0x
16.5x
18.3x
15.7x
16.1x
13.4x
15.4x
15.9x
15.3x
15.2x
15.0x
14.7x
14.8x
14.5x
14.1x
14.4x
13.3x
12.8x
12.9x
12.9x
16.1x
16.0x
15.7x
15.5x
15.4x
15.3x
15.1x
15.0x
14.4x
14.3x
14.0x
14.0x
13.9x
13.8x
13.7x
13.4x
13.0x
12.8x
12.5x
12.3x
15.0x
15.7x
14.8x
15.3x
14.7x
13.0x
13.6x
14.5x
13.4x
13.0x
13.4x
13.3x
13.3x
13.1x
13.4x
12.7x
12.4x
11.6x
12.0x
12.0x
6.1%
3.5%
6.4%
2.2%
4.9%
-0.5%
3.3%
5.4%
10.0%
5.5%
5.1%
4.2%
3.6%
5.6%
5.4%
6.5%
17.7%
2.9%
3.9%
5.2%
2.4x
1.5x
2.6x
1.6x
2.3x
1.6x
1.7x
2.1x
1.7x
1.7x
1.6x
1.4x
1.3x
1.4x
1.4x
2.1x
1.1x
1.4x
1.8x
1.3x
14.9x
18.3x
12.8x
14.3x
16.1x
12.3x
13.5x
15.7x
11.6x
5.3%
17.7%
-0.5%
1.7x
2.6x
1.1x
Prem. to
Group
12%
12%
10%
8%
8%
7%
5%
5%
1%
0%
-2%
-2%
-3%
-4%
-4%
-6%
-9%
-11%
-13%
-14%
Diversified Utilities
Ticker
Company Name
AEE
FE
ETR
NEE
EXC
CEG
PPL
PEG
Ameren Corp
FirstEnergy Corp
Entergy Corp
NextEra Energy, Inc.
Exelon Corp
Constellation Energy Group Inc
PPL Corp
Public Service Enterprise Group Inc
Diversified Group Average
Diversified Group Max
Diversified Group Min
4/24/12
Price
$31.93
$45.93
$65.94
$63.90
$37.94
$37.23
$27.27
$30.40
ISI
Rating
HOLD
BUY
HOLD
HOLD
HOLD
HOLD
HOLD
HOLD
Shares
Out
241
401
178
419
665
202
551
507
Market
Cap
7,709
18,406
11,767
26,804
25,221
7,506
15,024
15,412
2012
Div Yld
2012
Payout
5.0%
4.8%
5.0%
3.6%
5.5%
2.6%
5.3%
4.5%
67%
65%
60%
53%
67%
38%
64%
54%
4.5%
5.5%
2.6%
58%
67%
38%
ISI EPS Estimate
2012
2013
2014
2.40
3.40
5.50
4.35
3.15
2.50
2.25
2.55
2.05
3.15
4.80
4.90
2.95
3.10
2.35
2.65
2.20
3.45
4.85
5.10
2.90
3.15
2.05
2.65
2012
P/E Multiple
2013
2014
'11-'15
EPS Growth
Price to
Book
13.3x
13.5x
12.0x
14.7x
12.0x
14.9x
12.1x
11.9x
15.6x
14.6x
13.7x
13.0x
12.9x
12.0x
11.6x
11.5x
14.5x
13.3x
13.6x
12.5x
13.1x
11.8x
13.3x
11.5x
-2.6%
2.4%
-10.5%
5.3%
-6.7%
1.4%
-4.7%
1.3%
1.0x
2.2x
1.4x
1.9x
1.9x
1.0x
1.8x
1.6x
13.1x
14.9x
11.9x
13.1x
15.6x
11.5x
13.0x
14.5x
11.5x
-1.7%
5.3%
-10.5%
1.6x
2.2x
1.0x
Prem. to
Group
12%
4%
-2%
-7%
-8%
-14%
-17%
-18%
2
Source: ISI Research
Independent Power Producers - Comps
Ticker
Company Name
4/24/12
Price
Target
Price
ISI
Rating
2012
EBITDA
2013
2014
2015
2012
NRG
CPN
GEN
DYN
NRG Energy Inc
Calpine Corp
GenOn Corp
Dynegy Inc
$15.90
$18.07
$1.96
$0.33
$24.50
$17.00
$3.30
NA
BUY
BUY
HOLD
HOLD
1,801
1,712
531
355
1,400
1,823
632
412
1,195
1,862
598
286
1,273
1,883
520
382
-143
304
-274
-215
Ticker
Company Name
Current
Shares
Equity
Value
Enterprise
Value
2012
EV / EBITDA
2013
2014
2015
2012
NRG
CPN
GEN
DYN
NRG Energy Inc
Calpine Corp
GenOn Corp
Dynegy Inc
240
482
772
122
3,816
8,718
1,513
41
14,873
20,589
7,334
7,176
6.4x
10.2x
8.8x
11.6x
7.0x
9.2x
7.0x
10.5x
7.3x
8.7x
7.1x
15.9x
6.7x
8.3x
8.0x
12.4x
9.2x
8.4x
9.8x
8.8x
Average
Ticker
Company Name
Credit Ratings
S&P
Moody's
NRG
CPN
GEN
DYN
NRG Energy Inc
Calpine Corp
GenOn Corp
Dynegy Inc
BBB+
B
CC
Average
Ba3
B1
B2
NA
Price to
Book
0.5x
1.9x
0.3x
0.0x
Short and Long Term Debt
2012
2013
2014
2015
9,169
10,308
4,396
5,462
9,062
10,192
4,521
5,462
8,955
10,076
4,521
5,462
8,848
9,960
4,521
5,462
Free Cash Flow $m
2013
2014
2015
2012
Capex $m
2013
2014
2015
446
571
129
-176
-450
-310
-464
-195
-350
-230
-155
-195
-350
-230
-155
-165
-350
-230
-155
-165
Free Cash Flow Yield
2013
2014
2015
2012
EOP Cash
2013
2014
2015
1,392
1,433
1,257
1,373
1,591
1,425
1,603
1,192
1,651
1,508
1,897
784
605
508
221
-181
428
544
164
-232
-3.9%
17.8%
13.4%
14.8%
3.5%
6.2%
7.0%
7.8%
-18.1%
14.6%
10.8%
8.5%
-528.3% -445.3% -570.7% -432.5%
2012
Debt / Total Capital
2013
2014
2015
2012
1,612
1,453
1,767
960
Net Debt / EBITDA
2013
2014
2015
53%
71%
47%
71%
54%
71%
48%
73%
55%
72%
49%
76%
55%
72%
50%
78%
4.3x
5.2x
5.9x
11.5x
5.3x
4.8x
4.6x
10.4x
6.1x
4.6x
4.6x
15.7x
5.7x
4.5x
5.0x
12.3x
61%
62%
63%
64%
6.7x
6.3x
7.8x
6.9x
3
Source: ISI Research
Power & Utilities Performance
FY '10
1
2
3
4
5
Regulated
S&P 500
Index
Diversified
IPPs
10
16.2%
12.8%
7.5%
(7.7%)
(16.8%)
FY '11 - 1/1/11 to 12/31/11
10
1
Regulated
20.5%
2
Diversified
18.1%
3
Index
16.1%
4
S&P 500
(0.0%)
5
IPPs
(16.8%)
Q4 - 10/1/11 to 12/31/11
10
1
S&P 500
11.2%
2
Regulated
10.0%
3
Index
7.2%
4
Diversified
6.2%
5
IPPs
(9.4%)
YTD - 1/1/12 to 4/24/12
10
1
S&P 500
11.1%
2
Regulated
0.3%
3
Index
(3.6%)
4
Diversified
(3.7%)
5
IPPs
(28.6%)
MTD - 2/29/12 to 4/24/12
10
1
S&P 500
2.3%
2
Regulated
2.2%
3
Diversified
1.0%
4
Index
(0.4%)
5
IPPs
(20.9%)
WTD - 4/17/12 to 4/24/12
10
1
Regulated
0.9%
2
Index
0.7%
3
IPPs
0.6%
4
Diversified
0.2%
5
S&P 500
(0.5%)
Trough - 8/8/11 to 12/31/11
10
1
Regulated
25.3%
2
Index
20.5%
3
Diversified
19.7%
4
S&P 500
12.3%
5
IPPs
(9.2%)
27.6%
27.4%
23.0%
21.5%
21.3%
21.3%
20.1%
19.1%
19.0%
17.1%
16.7%
15.7%
15.0%
14.8%
14.7%
14.6%
14.5%
14.4%
12.8%
12.8%
12.1%
11.4%
11.2%
9.1%
9.0%
8.3%
6.4%
2.2%
(0.2%)
(3.5%)
(9.5%)
(10.2%)
(10.5%)
(14.2%)
(15.6%)
(17.2%)
(33.4%)
(37.9%)
FY '11 - 1/1/11 to 12/31/11
10
1
PGN
35.1%
2
CEG
32.6%
3
ED
30.0%
4
AWK
29.5%
5
DUK
29.1%
6
D
28.9%
7
OGE
27.8%
8
SO
26.0%
9
FE
25.6%
10 DTE
25.3%
11 UIL
23.8%
12 CMS
23.2%
13 AEE
23.0%
14 CPN
22.4%
15 WEC
22.3%
16 XEL
21.8%
17 HE
21.6%
18 POR
21.4%
19 NEE
21.3%
20 PNW
21.3%
21 AEP
20.0%
22 NVE
19.9%
23 WR
19.5%
24 POM
17.2%
25 PPL
17.1%
26 NU
16.6%
27 NST
16.0%
28 SCG
15.8%
29 TE
12.3%
30 EIX
10.6%
31 EXC
9.2%
32 SRE
8.5%
33 PEG
8.1%
34 ETR
7.8%
35 NRG
(7.3%)
36 PCG
(10.0%)
37 GEN
(31.5%)
38 DYN
(50.7%)
Q4 - 10/1/11 to 12/31/11
10
1
OGE
19.4%
2
CPN
16.0%
3
NEE
13.7%
4
PNW
13.4%
5
XEL
13.0%
6
TE
13.0%
7
CMS
12.6%
8
AEE
12.6%
9
SCG
12.6%
10 WEC
12.6%
11 DTE
12.3%
12 NVE
12.0%
13 ETR
11.4%
14 DUK
11.3%
15 SO
10.4%
16 HE
10.3%
17 WR
10.1%
18 PGN
10.0%
19 AEP
9.9%
20 ED
9.8%
21 EIX
9.1%
22 UIL
8.7%
23 POM
8.7%
24 NU
8.0%
25 POR
7.9%
26 SRE
7.7%
27 NST
6.4%
28 AWK
6.3%
29 D
5.5%
30 CEG
4.9%
31 PPL
4.3%
32 EXC
3.0%
33 PEG
(0.1%)
34 FE
(0.1%)
35 PCG
(1.5%)
36 GEN
(6.1%)
37 NRG
(14.6%)
38 DYN
(32.8%)
YTD - 1/1/12 to 4/24/12
10
1
SRE
17.6%
2
CPN
10.7%
3
AWK
7.1%
4
PCG
6.6%
5
NEE
5.9%
6
FE
4.9%
7
EIX
4.9%
8
DTE
3.9%
9
WEC
3.4%
10 NST
2.4%
11 SCG
2.3%
12 CMS
1.8%
13 NU
1.8%
14 POR
1.3%
15 PNW
0.9%
16 SO
0.1%
17 HE
(0.0%)
18 NVE
(0.4%)
19 WR
(0.7%)
20 AEE
(2.4%)
21 XEL
(2.4%)
22 DUK
(2.6%)
23 D
(3.3%)
24 UIL
(4.0%)
25 ED
(4.3%)
26 CEG
(5.5%)
27 PGN
(5.6%)
28 OGE
(5.7%)
29 TE
(5.9%)
30 PPL
(6.1%)
31 POM
(6.1%)
32 AEP
(6.2%)
33 PEG
(6.8%)
34 ETR
(8.6%)
35 EXC
(11.0%)
36 NRG
(12.3%)
37 GEN
(24.9%)
38 DYN
(88.0%)
MTD - 2/29/12 to 4/24/12
10
1
CPN
18.0%
2
SRE
9.2%
3
NEE
7.4%
4
PCG
5.4%
5
WEC
5.2%
6
DTE
4.8%
7
HE
4.4%
8
POR
4.0%
9
NVE
3.9%
10 WR
3.9%
11 CMS
3.9%
12 SO
3.8%
13 EIX
3.7%
14 FE
3.7%
15 CEG
3.3%
16 SCG
2.4%
17 PNW
2.3%
18 XEL
1.8%
19 AEP
1.8%
20 NST
1.6%
21 NU
1.4%
22 DUK
1.2%
23 OGE
1.1%
24 ED
1.1%
25 AEE
0.8%
26 D
0.7%
27 PEG
(0.1%)
28 TE
(0.8%)
29 ETR
(1.0%)
30 AWK
(1.1%)
31 PGN
(1.6%)
32 POM
(2.0%)
33 EXC
(2.5%)
34 PPL
(3.2%)
35 UIL
(3.7%)
36 NRG
(7.0%)
37 GEN
(20.3%)
38 DYN
(74.5%)
WTD - 4/17/12 to 4/24/12
10
1
NRG
5.8%
2
CPN
5.7%
3
HE
3.1%
4
PNW
1.9%
5
DUK
1.7%
6
WR
1.7%
7
AWK
1.6%
8
SCG
1.4%
9
NEE
1.4%
10 POM
1.3%
11 PGN
1.3%
12 CMS
1.2%
13 DTE
1.1%
14 TE
1.1%
15 SO
1.1%
16 NVE
0.9%
17 PCG
0.9%
18 ED
0.9%
19 XEL
0.8%
20 AEP
0.7%
21 WEC
0.7%
22 PPL
0.7%
23 OGE
0.6%
24 POR
0.4%
25 EIX
0.3%
26 FE
0.3%
27 NU
0.3%
28 PEG
0.3%
29 AEE
0.2%
30 SRE
0.1%
31 NST
0.0%
32 EXC
(0.3%)
33 D
(0.4%)
34 GEN
(0.5%)
35 UIL
(0.7%)
36 ETR
(0.8%)
37 DYN
(8.5%)
38 NST
0.0%
Trough - 8/8/11 to 12/31/11
10
1
OGE
38.7%
2
NVE
33.0%
3
PGN
31.7%
4
SCG
31.1%
5
AEE
30.6%
6
DUK
30.3%
7
CMS
29.9%
8
WR
29.3%
9
HE
28.7%
10 XEL
28.3%
11 PNW
28.2%
12 WEC
27.0%
13 AWK
26.5%
14 DTE
26.3%
15 EIX
26.3%
16 CPN
26.1%
17 ED
25.4%
18 ETR
25.4%
19 NEE
23.5%
20 AEP
23.2%
21 POM
22.8%
22 SRE
22.7%
23 SO
22.0%
24 NST
21.4%
25 TE
21.4%
26 NU
20.2%
27 POR
20.1%
28 UIL
19.7%
29 PPL
18.9%
30 D
17.7%
31 PEG
16.8%
32 CEG
16.8%
33 FE
14.4%
34 EXC
11.2%
35 PCG
6.3%
36 NRG
(11.0%)
37 GEN
(15.5%)
38 DYN
(36.5%)
FY '10
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
NU
OGE
CMS
WR
WEC
CPN
SO
PNW
NST
NVE
AWK
XEL
HE
TE
POM
EIX
D
ED
UIL
SCG
PGN
POR
PCG
DUK
DTE
AEP
AEE
NEE
PEG
SRE
ETR
CEG
EXC
PPL
FE
NRG
GEN
DYN
4
Source: FactSet, ISI Research
Table of Contents
Regulated Electric Utilities
Diversified Electric Utilities & IPPs
• General Overview
• How the Power Markets Work: Key Commodities, Supply, Demand
• Key Debates in the Power Markets
• Valuation Overview
5
Regulated Names Have Given Ground To The Market
Relative Performance Since 1/1/2011
Regulated
113
S&P500
Diversified
103
93
83
73
13 Nat Gas
63
Dec-10
Mar-11
SP50
May-11
Jul-11
Regulated
Sep-11
Diversified
Nov-11
Jan-12
Mar-12
13 Nat Gas
6
Absolute Valuation Doesn’t Look Stretched
…But Valuation vs. The S&P 500 Remains High
PEs of Regulateds Have Recently Been Stable
Relative PE on Next-Twelve Months Forward
Consensus EPS Is High Despite Recent
Moderation
Regulated NTM PE - Consensus EPS
Relative PE - NTM Consensus EPS
18.0x
1.4x
16.0x
1.2x
14.0x
1.0x
12.0x
0.8x
10.0x
0.6x
8.0x
0.4x
6.0x
Dec-95
Dec-97
Dec-99
Dec-01
Dec-03
Regulated NTM PE
Dec-05
Dec-07
Dec-09
Average NTM PE
Dec-11
0.2x
Dec-95
Dec-97
Dec-99
Dec-01
Dec-03
Dec-05
Dec-07
Regulated NTM PE vs. S&P PE
Dec-09
Dec-11
Average Rel PE
7
Source: FactSet, ISI Research
Bond Market Relationships Are More Relevant
•
•
Think in “3D”
Dividend yields are correlated to the relationship between long-term
treasury bond yields and corporate bond yields
•
R^2 of dividend yields to bond yields (1986 – Present)
– 10 YR = 0.764
– 30 YR = 0.796
– BBB’s = 0.834
Spread Between BAA Corporate Bond Yields and 10 YR Treasury Yield
7.0%
6.0%
5.0%
4.0%
3.0%
2.0%
1.0%
0.0%
Jan-70
Jul-78
Dec-86
Jun-95
Nov-03
Apr-12
8
Source: FactSet, ISI Research
Valuation vs. Bonds Is Less Supportive
BBB Bond Yield vs. Treasury Yields
3.5x
3.0x
2.5x
2.0x
1.5x
1.0x
0.5x
Jan-70
Jul-78
Dec-86
Jun-95
Nov-03
Apr-12
• This relationship has dislocated.
Corporate bonds trade at a spread of
323 bp vs. 217 bp historical average,
narrowing since January
Dividend Yield Premium to 10 Year
Treasury Yield
3.0x
2.5x
2.0x
• Utilities have dislocated from
sovereign debt as well
1.5x
1.0x
0.5x
Jan-70
Jul-78
Dec-86
Jun-95
Nov-03
Apr-12
Dividend Yield to BAA Bond Yield
1.4x
…Again
The "Bill Gross" Thesis..
1.2x
• Utilities remain correlated to
corporate bonds, and are still a bit
cheap, but less so
1.0x
0.8x
0.6x
0.4x
Jan-70
Feb-76
Feb-82
Mar-88
Mar-94
Mar-00
Apr-06
*Dotted red lines represent +1/-1Standard Deviations, while solid red line is the mean.
Apr-12
9
Source: FactSet, ISI Research
Valuation vs. Bonds Is Less Supportive
• Dividend Yield / Corporate Bond Yield Relationship looked different before the
financial crisis—so perhaps valuation can withstand higher bond yields.
Dividend Yield to BBB Bond Yield
(Daily; Jan ’04- Present)
1.20x
1.10x
The “Bill Gross” Thesis
1.00x
Higher than early
April but
stabilizing
0.90x
0.80x
0.70x
0.60x
0.50x
0.40x
Jan-04
May-05
Sep-06
*Mean and Standard Deviations are calculated off of 1970 to present data set.
Feb-08
Jun-09
Oct-10
Mar-12
10
Source: FactSet, ISI Research
Regulated Names Have Given Ground To The Market
In ’11 stock performance was highly correlated with the S&P500 until midAugust, when the stocks became extremely cheap to the bond market.
Relative Performance vs. S&P500
20%
16%
12%
8%
4%
Inflection Point: Market
Corrects With Cheapness
to Bonds
0%
-4%
-8%
Dec-10
Feb-11
Apr-11
Jun-11
Aug-11
Oct-11
Dec-11
Feb-12
Aug-11
Oct-11
Dec-11
Feb-12
Relative Performance
Ratio of Div Yields to BBB Yields
1.05x
1.00x
0.95x
0.90x
0.85x
0.80x
0.75x
0.70x
0.65x
0.60x
0.55x
0.50x
Dec-10
Feb-11
Apr-11
Jun-11
Div to BBB
Mean
St Dev (L)
St Dev (H)
11
Dividend Yield / Bond Yield Regression Snapshots
The relationship has screened cheap to varying degrees, but was only actionable in
August ’11 when it broke through the 68% confidence interval.
Utility Valuation Trough Aug '11
8/8/11
Confidence Intervals
- 95.0% Confidence Interval
- 68.0% Confidence Interval
Predicted Valuation
+ 68.0% Confidence Interval
Current Valuation
+ 95.0% Confidence Interval
10 YR
BBB
BBB Yield %
2.28%
2.68%
3.08%
3.48%
3.68%
3.88%
4.28%
4.48%
4.88%
5.08%
5.28%
5.48%
5.68%
5.88%
6.08%
6.28%
6.68%
6.88%
7.08%
7.68%
8.08%
Expected
Defensive
Index Yld
1.78%
2.07%
2.35%
2.63%
2.77%
2.92%
3.20%
3.34%
3.63%
3.77%
3.91%
4.05%
4.19%
4.33%
4.48%
4.62%
4.90%
5.04%
5.19%
5.61%
5.89%
Implied
2013 P/E
34.8x
30.1x
26.4x
23.6x
22.4x
21.3x
19.4x
18.6x
17.1x
16.5x
15.9x
15.3x
14.8x
14.3x
13.9x
13.4x
12.7x
12.3x
12.0x
11.1x
10.5x
2.34%
5.28%
Upside /
(Downside)
for Index
196.6%
155.9%
125.0%
100.8%
90.5%
81.3%
65.2%
58.2%
45.8%
40.3%
35.2%
30.5%
26.1%
22.0%
18.1%
14.5%
7.9%
4.8%
2.0%
-5.8%
-10.3%
End of 3Q 2011
9/30/11
Confidence Intervals
- 95.0% Confidence Interval
- 68.0% Confidence Interval
Predicted Valuation
Current Valuation
+ 68.0% Confidence Interval
+ 95.0% Confidence Interval
10 YR
BBB
BBB Yield %
2.22%
2.62%
3.02%
3.42%
3.62%
3.82%
4.22%
4.42%
4.82%
5.02%
5.22%
5.42%
5.62%
5.82%
6.02%
6.22%
6.62%
6.82%
7.02%
7.62%
8.02%
Expected
Defensive
Index Yld
1.75%
2.04%
2.32%
2.60%
2.74%
2.89%
3.17%
3.31%
3.59%
3.73%
3.88%
4.02%
4.16%
4.30%
4.44%
4.58%
4.87%
5.01%
5.15%
5.57%
5.86%
Implied
2013 P/E
35.5x
30.6x
26.9x
24.0x
22.7x
21.6x
19.7x
18.8x
17.4x
16.7x
16.1x
15.5x
15.0x
14.5x
14.0x
13.6x
12.8x
12.5x
12.1x
11.2x
10.6x
1.93%
5.22%
Upside /
(Downside)
for Index
167.2%
130.1%
102.0%
80.1%
70.8%
62.4%
47.9%
41.6%
30.4%
25.5%
20.9%
16.7%
12.7%
9.0%
5.5%
2.2%
-3.7%
-6.4%
-9.0%
-15.9%
-20.0%
Today
4/24/12
Confidence Intervals
- 95.0% Confidence Interval
- 68.0% Confidence Interval
Predicted Valuation
Current Valuation
+ 68.0% Confidence Interval
+ 95.0% Confidence Interval
10 YR
BBB
BBB Yield %
2.16%
2.56%
2.96%
3.36%
3.56%
3.76%
4.16%
4.36%
4.76%
4.96%
5.16%
5.36%
5.56%
5.76%
5.96%
6.16%
6.56%
6.76%
6.96%
7.56%
7.96%
Expected
Defensive
Index Yld
1.74%
2.03%
2.31%
2.59%
2.73%
2.87%
3.15%
3.29%
3.57%
3.71%
3.86%
4.00%
4.14%
4.28%
4.42%
4.56%
4.84%
4.98%
5.12%
5.54%
5.82%
Implied
2013 P/E
36.1x
31.1x
27.3x
24.3x
23.1x
21.9x
20.0x
19.1x
17.6x
17.0x
16.3x
15.8x
15.2x
14.7x
14.3x
13.8x
13.0x
12.6x
12.3x
11.4x
10.8x
1.93%
5.16%
Upside /
(Downside)
for Index
154.1%
118.9%
92.2%
71.3%
62.5%
54.5%
40.7%
34.7%
24.1%
19.4%
15.0%
11.0%
7.2%
3.7%
0.4%
-2.7%
-8.4%
-11.0%
-13.4%
-20.0%
-23.9%
12
Source: FactSet, ISI Research
Valuation Looks Low vs. Bonds…
•
•
Valuation Sensitivity to Dividend Tax / Interest Rate Assumption: Bond
Correlations
Bear Case 13.1x; Bull Case 16.3x; Our Target is 14.7x ’13 EPS
Scenarios:
Rate Assumptions
10 Year Treasury Yield
Assumed BAA Bond Yield
Low Rates /
Low Taxes
High Rates /
Low Taxes
Low Rates /
High Taxes
High Rates /
High Taxes
Current
Situation
1.93%
5.16%
3.50%
6.00%
1.93%
5.16%
3.50%
6.00%
1.93%
5.16%


Tax Assumptions
Tax Rate Levelized at Ordinary Income Tax Rate
2
1


Target 2013 PE
Target 2012 Dividend Yield
16.3x
3.9%
14.2x
4.4%
15.2x
4.1%
13.1x
4.8%
Upside to our Target Multiple of 14.7x
Upside to Current Market Multiple of 14.2x
10.8%
14.9%
-3.8%
-0.2%
3.3%
7.1%
-11.2%
-7.9%
Tax Rate Levelized at 15% Income Tax Rate
Market
Multiple
14.2x
4.2%
Note: Averages based on our regulated coverage universe
1) Assumes a positive adjustment to post 2003 dividends in our regression series by approximately 7%. This represents the delta between the current 15%
dividend tax rate and an assumed rate of 33%, adjusted by our assumption that 40% of shareholders are individual taxpayers. The sensitivity to the
PE mutliple from a 1% change in the assumed tax rate is 0.1x. The sensitivity to the PE multiple from a 10% change in our assumption relating to the
proportion of tax-paying shareholders is 0.1x
2) Assumes a negative adjustment to pre 2003 dividends in our regression series by approximately 11%. This represents the delta between the current 15%
dividend tax rate and a pre-2003 assumed rate of 33%, redued by our assumption that 60% of shareholders were individual tax payers. The sensitivity to the
PE mutliple from a 1% change in the assumed tax rate is 0.1x. The sensitivity to the PE multiple from a 10% change in our assumption relating to the
proportion of tax-paying shareholders is 0.1x
13
Source: FactSet, ISI Research
Utilities Tend To Underperform With Rising Rates
Utilities have had negative absolute returns in 3 of the 5 periods where 10Yr yields have risen meaningfully and lagged
the market in 4 of the 5 periods.
Period #1
Period #2
Period #3
Period #4
Period #5
Historical Avg.
Current
Beg. Date
Dec-95
Sep-98
May-03
Dec-08
Aug-10
Feb-12
Summary: How do Regulated Electric Utility stocks do in periods of rising 10Yr rates
Annualized Basis
Across time period
Length of
Regulated Utiliy Return
Regulated Utiliy Return
End Date 10Yr Rate Rise ∆ 10Yr Yields Utility Stocks Less S&P
∆ 10Yr Yields Utility Stocks Less S&P
Jun-96
0.5yrs
139bp
-4%
-12%
268bp
-9%
-24%
Jan-00
1.3yrs
217bp
-20%
-58%
172bp
-16%
-46%
Apr-06
2.9yrs
171bp
55%
14%
58bp
19%
5%
May-09
0.4yrs
155bp
-8%
-7%
351bp
-19%
-16%
Feb-11
0.5yrs
109bp
11%
-16%
226bp
22%
-33%
1.1yrs
158bp
7%
-16%
140bp
6%
-14%
Mar-12
0.1yrs
44bp
1%
-5%
385bp
5%
-42%
Corporate yields and corporate bond trends in times of rising 10Yr rates
Period #1
Period #2
Period #3
Period #4
Period #5
Historical Avg.
Current
Period #1
Period #2
Period #3
Period #4
Period #5
Historical Avg.
Current
Beg. Date
Dec-95
Sep-98
May-03
Dec-08
Aug-10
Feb-12
Beg. Date
Dec-95
Sep-98
May-03
Dec-08
Aug-10
Feb-12
Summary: How do Utilities stocks do in periods of changing BAA Corp Bond Spreads?
Across time period
Annualized Basis
Utility Return
Utility Return
Length of
End Date
10Yr Rate Rise ∆ BAA Spreads Utility Stocks Less S&P
∆ BAA Spreads Utility Stocks Less S&P
Jun-96
0.5yrs
-36bp
-4%
-12%
-69bp
-9%
-24%
Jan-00
1.3yrs
-89bp
-20%
-58%
-71bp
-16%
-46%
Apr-06
2.9yrs
-120bp
55%
14%
-41bp
19%
5%
May-09
0.4yrs
-158bp
-8%
-7%
-358bp
-19%
-16%
Feb-11
0.5yrs
-42bp
11%
-16%
-87bp
22%
-33%
1.1yrs
-89bp
7%
-16%
-79bp
6%
-14%
Mar-12
0.1yrs
24bp
1%
-5%
209bp
5%
-42%
Summary: How do Utilities stocks do in periods of changing BAA Corp Bond Yields?
Across time period
Annualized Basis
Utility Return
Utility Return
Length of
End Date
10Yr Rate Rise ∆ BAA Yields Utility Stocks Less S&P
∆ BAA Yields
Utility Stocks Less S&P
Jun-96
0.5yrs
103bp
-4%
-12%
199bp
-9%
-24%
Jan-00
1.3yrs
128bp
-20%
-58%
101bp
-16%
-46%
Apr-06
2.9yrs
51bp
55%
14%
17bp
19%
5%
May-09
0.4yrs
-3bp
-8%
-7%
-7bp
-19%
-16%
Feb-11
0.5yrs
67bp
11%
-16%
140bp
22%
-33%
1.1yrs
69bp
7%
-16%
61bp
6%
-14%
Mar-12
0.1yrs
24bp
1%
-5%
209bp
5%
-42%
14
Source: ISI REIT Team, FactSet, Bloomberg
Regulated Utility Comps
• Focus on value and second tier quality names
Regulated Utilities
Ticker
Company Name
SO
PGN
NST
ED
D
PCG
SRE
WEC
HE
NU
XEL
DTE
DUK
WR
PNW
CMS
NVE
AEP
TE
EIX
Southern Company Inc
Progress Energy Inc
NStar
Consolidated Edison Inc
Dominion Resources Inc
PG&E Corp
Sempra Energy
Wisconsin Energy Corp
Hawaiian Electric Industries, Inc.
Northeast Utilities
Xcel Energy Inc
DTE Energy Co
Duke Energy Corp
Westar Energy Inc
Pinnacle West Capital Corp
CMS Energy Corp
NV Energy
American Electric Power Co Inc
Teco Energy Inc
Edison International
Regulated Group Average
Regulated Group Max
Regulated Group Min
4/24/12
Price
$45.87
$52.24
$47.65
$58.73
$50.81
$43.48
$64.09
$35.84
$26.16
$36.41
$26.71
$55.98
$21.18
$28.26
$48.11
$22.24
$16.16
$38.27
$17.80
$43.10
ISI
Rating
HOLD
SELL
HOLD
SELL
HOLD
BUY
HOLD
HOLD
HOLD
HOLD
HOLD
HOLD
HOLD
BUY
BUY
HOLD
HOLD
HOLD
HOLD
BUY
Shares
Out
863
296
104
294
575
403
242
235
96
178
486
170
1,333
118
110
263
237
482
215
328
Market
Cap
39,607
15,450
4,955
17,286
29,192
17,522
15,483
8,439
2,507
6,472
12,968
9,517
28,222
3,340
5,274
5,855
3,837
18,457
3,831
14,137
2012
Div Yld
2012
Payout
4.3%
4.7%
3.8%
4.1%
4.2%
4.2%
3.7%
3.3%
4.7%
3.5%
4.0%
4.4%
4.8%
4.7%
4.4%
4.3%
3.5%
4.8%
5.0%
3.0%
72%
78%
69%
65%
67%
56%
58%
53%
73%
53%
60%
64%
71%
68%
63%
62%
47%
62%
65%
38%
4.2%
5.0%
3.0%
62%
78%
38%
ISI EPS Estimate
2012
2013
2014
2.70
3.17
2.61
3.75
3.15
3.25
4.15
2.26
1.70
2.40
1.78
3.80
1.43
1.95
3.40
1.55
1.22
3.00
1.38
3.35
2.85
3.27
3.03
3.80
3.30
2.85
4.25
2.38
1.82
2.55
1.90
4.00
1.52
2.05
3.50
1.65
1.24
3.00
1.43
3.50
2012
3.05
3.34
3.22
3.85
3.45
3.35
4.70
2.47
1.95
2.80
2.00
4.20
1.60
2.15
3.60
1.76
1.30
3.30
1.48
3.60
P/E Multiple
2013
2014
'11-'15
EPS Growth
Price to
Book
17.0x
16.5x
18.3x
15.7x
16.1x
13.4x
15.4x
15.9x
15.3x
15.2x
15.0x
14.7x
14.8x
14.5x
14.1x
14.4x
13.3x
12.8x
12.9x
12.9x
16.1x
16.0x
15.7x
15.5x
15.4x
15.3x
15.1x
15.0x
14.4x
14.3x
14.0x
14.0x
13.9x
13.8x
13.7x
13.4x
13.0x
12.8x
12.5x
12.3x
15.0x
15.7x
14.8x
15.3x
14.7x
13.0x
13.6x
14.5x
13.4x
13.0x
13.4x
13.3x
13.3x
13.1x
13.4x
12.7x
12.4x
11.6x
12.0x
12.0x
6.1%
3.5%
6.4%
2.2%
4.9%
-0.5%
3.3%
5.4%
10.0%
5.5%
5.1%
4.2%
3.6%
5.6%
5.4%
6.5%
17.7%
2.9%
3.9%
5.2%
2.4x
1.5x
2.6x
1.6x
2.3x
1.6x
1.7x
2.1x
1.7x
1.7x
1.6x
1.4x
1.3x
1.4x
1.4x
2.1x
1.1x
1.4x
1.8x
1.3x
14.9x
18.3x
12.8x
14.3x
16.1x
12.3x
13.5x
15.7x
11.6x
5.3%
17.7%
-0.5%
1.7x
2.6x
1.1x
Prem. to
Group
12%
12%
10%
8%
8%
7%
5%
5%
1%
0%
-2%
-2%
-3%
-4%
-4%
-6%
-9%
-11%
-13%
-14%
• “Quality” is at a premium 15-17x 2012 EPS: D, ED, SO, WEC
• “Value” is at a discount, 13-14x 2012 EPS: AEP, CMS, EIX, NVE, PCG, PNW, SRE, TE
• “Second Tier Quality” in the middle: DTE, DUK, HE, NU, WR, XEL
15
Source: ISI Research
4 Key Drivers for Utilities: Regulation & Economic Growth
1. Regulatory Environment – The key factor that determines a utility’s ability to make new investments,
earn a fair return, and sets the level at which the company will finance externally.
2. Rate Base Growth – Rate base represents the amount invested by the utility in the electric system
Rate Base
Capex > Depreciation
Rate Base Growth
≈
PPE
Capex < Depreciation
Declining Rate Base
—
Depreciation
±
Deferred Taxes
3. Returns – Set by regulators. CAPM, DCF models often used to determine allowed return on equity
Key Formulas:
Net Income = Rate Base x Allowed Equity Ratio x Allowed Return on Equity
Revenue = Cost + Profit
4. Regulatory Compact – A utility should be allowed to earn a “fair and reasonable” return
on its “used and useful” capital investments and recover “prudently incurred” costs.
16
Source: ISI Research
Regulated Utilities: Key Drivers
Earnings = ƒ (Assets, Allowed Returns, Capital
Ratios)
Category
Driver
Recent Impact
Commentary
Assets
Rate Base Growth
Positive
T&D Upgrades needed to improve system reliability
and move renewable energy to loads and install the
“smart grid”. Capex for generation assets.
Environmental retrofits needed to meet tightening
regulatory standards.
Allowed Returns
Rate Cases
Neutral/Positive
Allowed ROEs have been generally stable.
Recessionary pressures have not driven confiscatory
decisions in most states
Neutral
Equity Ratio is determined by regulators and
companies manage to prescribed levels. These have
remained stable due to regulators being mindful of
credit metrics.
Capital Ratios
Rate Cases
17
Source: ISI Research
Rate Case Anatomy: Determining Revenue Requirement
Net Income = (Rate Base x Allowed ROE x Allowed Equity Ratio)
Federal Income Taxes
Capital Cost (interest & Principal expense)
Taxes (property & franchise)
Depreciation
O&M
Fuel (pass through if utility has a fuel clause)
Third Party Revenues (e.g., off-system sales)
Revenue Requirement
18
Source: ISI Research
Regulatory Environment: Why It Matters
19
Source: ISI Research
Virtuous Cycle Has Been Maintained
•
•
•
Low (Non-existent) inflation
Plummeting Natural Gas Prices
Government Stimulus
16.0
14.0
12.0
10.0
8.0
6.0
4.0
2.0
0.0
1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010
Residential
Commercial
Industrial
Total
Inflation
20
Source: EIA, BLS, ISI Research
While Rate Base Has Grown
90
80
70
60
50
40
30
20
10
0
72
62
68
12
42
16
26
35
77
73
44
43
39
67
53
36
77
45
38
36
25
26
27
27
28
30
31
32
33
35
2004A
2005A
2006A
2007A
2008A
2009A
2010A
2011E
2012E
2013E
Adjusted D&A
PP&E Growth
21
Source: SNL Research, ISI Research
Authorized ROEs Widened vs. Cost of Equity
Range For Authorized ROE: 10% to 12.4%
Allowed ROEs Highly Correlated with BBB Yields
18.00
45
16.00
40
25
10.00
20
8.00
15
6.00
10
4.00
5
0
1983
1986
Number of Cases
1989
1992
1995
Authorized ROE
1998
2001
US 10 Year
2004
2007
2010
BBB Corp Bond Yld
# of Rate Cases
30
12.00
Yield (%)
15.00%
35
14.00
2.00
1980
BBB Yield vs. Allowed Utility ROE
17.50%
2
R = 0.89
12.50%
10.00%
7.50%
5.00%
5.0%
7.5%
10.0%
12.5%
15.0%
17.5%
BBB Yield
22
Source: SNL Research, FactSet, ISI Research
Impact of 50bp Decrease in Authorized ROEs
2013 Target Multiple expands with a 50bps decrease in authorized ROEs
Ticker
NST
PCG
WR
PNW
D
SRE
SO
NU
ED
DUK
WEC
EIX
DTE
NVE
XEL
PGN
HE
TE
CMS
AEP
Average
'13 EPS ($)
3.03
2.85
2.05
3.50
3.30
4.25
2.85
2.55
3.80
1.52
2.38
3.50
4.00
1.24
1.90
3.27
1.82
1.43
1.65
3.00
Proforma
'13 EPS ($)
2.86
2.71
1.94
3.30
3.22
4.13
2.76
2.48
3.61
1.42
2.31
3.19
3.83
1.16
1.80
3.13
1.75
1.37
1.57
2.87
'13 Payout
61.1%
63.9%
67.6%
64.5%
67.6%
58.4%
71.0%
54.2%
64.2%
68.0%
56.3%
36.6%
64.3%
53.2%
58.7%
75.8%
68.3%
65.3%
62.3%
63.0%
62.2%
Proforma
'13 Payout
64.6%
67.2%
71.3%
68.4%
69.4%
60.1%
73.2%
55.8%
67.6%
72.8%
58.1%
40.1%
67.2%
56.8%
62.1%
79.1%
70.8%
67.8%
65.7%
66.0%
65.2%
∆ in '13
OCF ($m)
-2
-64
-14
-22
-50
-29
-77
-23
-57
1,977
-17
626
-30
-19
-51
8
-7
-11
-23
-63
∆ in '13
Proforma
TD/Cap (bps) Target Mult Target Mult
-138
0
8
0
5
5
0
0
0
1,012
8
14
8
8
7
12
0
0
7
193
16.7x
16.5x
15.4x
15.1x
15.5x
15.3x
15.3x
15.1x
14.7x
14.4x
14.9x
14.0x
14.5x
14.1x
14.2x
14.4x
14.3x
13.7x
13.3x
13.3x
14.7x
17.6x
17.3x
16.2x
16.0x
15.9x
15.7x
15.7x
15.5x
15.5x
15.5x
15.4x
15.4x
15.1x
15.1x
15.0x
15.0x
14.9x
14.2x
14.0x
14.0x
15.5x
Multiple ∆
1.0x
0.9x
0.8x
0.9x
0.4x
0.4x
0.5x
0.4x
0.8x
1.0x
0.5x
1.3x
0.6x
0.9x
0.8x
0.6x
0.5x
0.5x
0.7x
0.6x
0.7x
23
Source: SNL Research, FactSet, ISI Research
Table of Contents
Regulated Electric Utilities
Diversified Electric Utilities & IPPs
• General Overview
• How the Power Markets Work: Key Commodities, Supply, Demand
• Key Debates in the Power Markets
• Valuation Overview
24
The Stay Of The CSAPR Rule Was A Modest Negative
•
•
•
What Happened: On Dec. 30, 2011, in a surprise decision the US
Court of Appeals, D.C. Circuit, granted a stay of the Cross State Air
Pollution Rule (CSAPR) just two days before it was set to be
implemented. CSAPR established a cap-and-trade system to
reduce power plant emissions of SO2 and NOx. The rule set
emissions limits on states and individual electric generating units
(EGUs) within the states. Oral arguments are in April 2012.
Un-scrubbed Coal Won, Clean Generators Lost: The decision
benefits un-scrubbed merchant coal generators GEN & EIX. The
decision negatively impacts scrubbed coal generators and merchant
nuclear/gas—like FE, EXC, PPL, PEG, ETR and CPN.
Power Market Impact Was Modest: We believe the impact to Cal
'12 –'13 pricing was likely modest, at (<$1 / MWh).
25
The EPA MAT Rule Will Bolster Capacity Pricing In ‘15
•
•
•
•
•
•
•
•
EPA’s long-awaited Utility MAT was announced on 12/21/11.
The rule was proposed on March 16, 2011, and requires coal and oil-fired
power plants to reduce emissions of Mercury, certain non-Mercury Metals,
and Acid gasses.
The rule was broadly in-line with what was proposed in March.
Expensive environmental retrofits will be required for power plants that do
not meet the mandated emissions standards.
Under section 112 of the Clean Air Act, all covered plants must be in
compliance by early 2015.
The EPA codified conditions under which extensions to the statutory
timeline (up to an additional 2 years) will be granted for plants that commit
to installing the required controls.
We expect that plants that deem it uneconomic to install controls will have
to retire by 2015 - unless required by regional grid operators for reliability
purposes.
We expect PJM capacity pricing to rise in the next auction, impacting
revenues for generators in 2015.
26
EPS Revisions Risk Has Moderated
2012E
FYE Dec 31,
AEE
ISI Estimated EPS
ISI Estimated EPS MTM
Consensus EPS
2013E
2014E
2015E
2013E
2014E
2015E
2.25
2.28
2.34
2.35
2.38
2.45
2.05
2.06
2.20
2.25
2.25
2.20
Delta to Prior
Delta to Consensus
1%
-3%
1%
-3%
0%
-6%
0%
2%
4.90
4.76
5.02
EXC
ISI EPS - Pro Forma
ISI Estimated EPS MTM
Consensus EPS
3.15
3.13
3.04
2.95
3.07
2.92
2.90
3.11
2.93
3.15
3.42
4.33
-2%
-14%
-5%
Pro Forma Delta to Prior
Delta to Consensus
-1%
3%
4%
5%
7%
6%
-21%
3.15
3.09
3.16
3.45
3.38
3.43
4.00
3.91
4.23
NEE
ISI Estimated EPS
ISI Estimated EPS MTM
Consensus EPS
4.35
4.39
4.52
4.90
4.92
4.96
5.10
5.11
5.15
5.35
5.36
5.52
-2%
-1%
-2%
-2%
-2%
-1%
-8%
Delta to Prior
Delta to Consensus
1%
-3%
1%
-1%
0%
-1%
-3%
2.55
2.29
2.39
2.65
2.34
2.47
2.65
2.34
2.52
2.90
2.57
2.50
-10%
-4%
-12%
-5%
-12%
-7%
-11%
3%
2.05
2.03
1.92
2.20
2.30
1.95
2.13
2.13 NA
0%
1%
-1%
6%
-11%
-7%
-8% NA
ETR
ISI Estimated EPS
ISI Estimated EPS MTM
Consensus EPS
5.50
5.41
5.56
4.80
4.76
5.37
4.85
4.75
5.52
Delta to Prior
Delta to Consensus
-2%
-3%
-1%
-12%
FE
ISI Estimated EPS
ISI Estimated EPS MTM
Consensus EPS
3.40
3.33
3.36
Delta to Prior
Delta to Consensus
PEG
ISI Estimated EPS
ISI Estimated EPS MTM
Consensus EPS
Delta to Prior
Delta to Consensus
2012E
PPL
ISI Estimated EPS
ISI Estimated EPS MTM
Consensus EPS
2.40
2.40
2.37
Delta to Prior
Delta to Consensus
FYE Dec 31,
Regulateds with Commodity Exposure
D
ISI Estimated EPS
ISI Estimated EPS MTM
Consensus EPS
3.15
3.12
3.22
3.30
3.30
3.43
3.45
3.44
3.52
3.70
3.70
3.78
AEP**
ISI Estimated EPS
ISI Estimated EPS MTM
Consensus EPS
3.00
2.94
3.11
3.00
3.03
3.23
3.30
2.99
3.32
3.50
3.34
3.40
Delta to Prior
Delta to Consensus
-1%
-3%
0%
-4%
0%
-2%
0%
-2%
Delta to Prior
Delta to Consensus
-2%
-6%
1%
-6%
-10%
-10%
-5%
-2%
3/28/12 - curve date
**EPS does not include retail load serving premium
27
Source: ISI Research
Price Targets Reflect Higher Capacity & Power/Gas Prices
•
•
Given near-term downside from negative earnings revisions, we see
headwinds until power and capacity market conditions improve
We do expect to see higher capacity prices in the upcoming ’15 / ’16
PJM Base Residual Auction (Held in May 2012)
AEE
ETR
Diversified Utilities
EXC
FE
NEE
PEG
PPL
CPN
IPPs
GEN
NRG
Current Price
31.49
66.27
37.65
45.76
62.80
30.10
26.90
17.67
1.94
14.97
2014 OPEN EBITDA Base Valuation
Plus: Capacity Market Uplift, 20151
Current Implied Valuation
30.75
0.00
30.75
72.37
0.30
72.68
39.16
5.51
44.68
28.92
19.12
48.03
60.12
-0.05
60.07
27.24
0.77
28.01
30.03
0.77
30.80
10.21
3.68
13.90
0.36
1.80
2.16
14.47
4.51
18.98
0.00
0.00
3.83
5.12
0.06
2.65
1.77
1.78
1.42
0.83
30.75
30.75
32.00
72.68
76.31
79.93
44.68
49.02
53.36
48.03
52.77
57.51
60.07
60.88
61.69
28.01
30.07
32.13
30.80
31.88
32.97
13.90
15.27
16.65
2.16
2.83
3.51
18.99
26.59
34.20
33.00
HOLD
73.00
HOLD
46.00
HOLD
50.00
BUY
60.00
HOLD
34.50
HOLD
30.00
HOLD
17.00
BUY
3.30
HOLD
24.50
BUY
1.51
4.8%
6.73
10.2%
8.35
22.2%
4.24
9.3%
-2.80
-4.5%
4.40
14.6%
3.10
11.5%
-0.67
-3.8%
1.36
70.1%
9.53
63.7%
0.00
0.00
0.00
0.00
138.78
199.42
81.84
202.68
187.61
159.45
203.59
225.00
180.96
216.97
156.23
189.10
152.78
202.24
145.11
145.22
Value Impact of + $50 / MW day in PJM
$4.00 / mmbtu Gas Case
$4.50 / mmbtu Gas Case
$5.00 / mmbtu Gas Case
Target Price
Rating
Expected Price Return to Target ($)
Expected Price Return to Target (%)
Blended PJM Capacity Price ('14 Earnings)1
Blended PJM Capacity Price (Valuation)
1) Capacity market uplift embedded in valuation case shown at bottom: "Blended PJM Capacity Price (Valuation)"
28
Source: ISI Research
Natural Gas Prices Now Around $4 in 2014
Falling strips imply big capex cut on the way: Gas prices have fallen
materially recently. Likewise, we are materially cutting individual company
gas production outlooks on expected capex cuts for low-margin drilling.
Natural Gas Futures Curves ($/MMBtu)
$7.00
2012
2013
2014
2015
$6.50
$6.00
$5.50
$5.00
$4.50
$4.00
$3.50
$3.00
2
/2
01
2
29
2/
31
/2
01
11
1/
/3
12
0/
/3
11
1/
20
11
20
11
20
1
/2
10
/3
1/
01
1
30
9/
8/
31
/2
01
01
/2
31
7/
30
/2
01
1
1
1
6/
31
/2
01
1
5/
30
/2
01
1
4/
/2
31
3/
/2
01
01
1
28
2/
31
/2
01
10
1/
20
1/
/3
1
$2.50
12
•
29
Source: Bloomberg and ISI E&P Research
Natural Gas Prices Now Around $4 in 2014
FALLING STRIPS IMPLY:
1) BIG CAPEX CUT ON THE WAY: Gas prices have fallen materially in recent weeks.
Likewise, we are materially cutting individual company gas production outlooks on
expected capex cuts for low-margin drilling.
2) DOWNSHIFT ALONG CURVE LIMITS HEDGING OPPORTUNITIES
3) GAS IS SUB-$5 THROUGH 2017
9/3/2009
$8.00
6/30/2009
3/31/2009
12/31/2008
3/21/2012
$6.50
12/30/2011
9/30/2011
6/30/2011
$6.00
$7.00
$5.50
$5.00
$6.00
$4.50
$5.00
$4.00
$3.50
$4.00
$3.00
$3.00
$2.50
$2.00
$2.00
2009
2010
2011
2012
2013
2012
2013
2014
2015
2016
30
Source: Bloomberg and ISI E&P Research
Diversified & IPP Performance vs. Gas & Power
Performance Since
Since 1/1/2005
1/1/2011
Relative Performance
244
194
144
Diversified
PJM Power
94
44
Jan-05
Nat Gas
IPPs
Jan-06
IPPs
Jan-07
Feb-08
Diversified
Feb-09
Nat Gas
Feb-10
Mar-11
Mar-12
PJM Power
31
Source: ISI Research
Diversified & IPP Performance vs. Gas & Power
Diversified
IPPs
PJM Power
Nat Gas
32
Source: ISI Research
Recent Commodity Price Trends – PJM West
ATC
ATC Power
Power Price
Price -- $/
$/ MWh
MWh
CAPP
CAPP Dark
Dark Spread
Spread -- $$ // MWh
MWh
60.00
50.00
45.81 45.81
48.67
45.80
45.15 44.71
16.00
14.94 14.94
14.14
14.00
43.18
40.81
37.82
40.00
54.79
51.79
11.79
12.00
33.79
9.45
10.00
30.00
7.78
8.00
8.07
8.00
6.00
20.00
4.00
10.00
3.32
2.53
1.03
2.00
.00
.00
2010
2011
2012
04/04/12
2013
2014
2015
2010
2011
2012
09/28/11
2013
04/04/12
On-Peak
On-Peak Spark
Spark Spread
Spread -- $$ // MWh
MWh
2014
2015
09/28/11
On-Peak
On-Peak Market
Market Implied
Implied Heat
Heat Rate
Rate -- mmbtu
mmbtu // MWh
MWh
25.00
16,000.00
20.80
20.00
2.58
19.25
18.68 18.68
17.97
17.84 17.89
19.23
17.74
20.09
18.56
12,000.00
10.7 10.7
11.7
11.4
10.6
9.6
10,000.00
13.62
15.00
13.5
14,000.00
10.3
11.1
10.4
11.1
10.3
8,000.00
10.00
6,000.00
4,000.00
5.00
2,000.00
.00
.00
2010
2011
2012
04/04/12
2013
09/28/11
Note: all of the above data shown for Cal 2012 forwards
2014
2015
2010
2011
2012
04/04/12
2013
2014
2015
09/28/11
33
Source: ISI Research
Recent Commodity Price Trends – AD Hub
ATC
ATC Power
Power Price
Price -- $/
$/ MWh
MWh
CAPP
CAPP Dark
Dark Spread
Spread -- $$ // MWh
MWh
12.00
60.00
50.00
40.00
37.05 37.05
43.23
39.99
38.76 36.70
30.76
39.46
37.35
34.37
50.35
46.96
8.00
6.18
6.97
6.18
6.00
30.00
4.01
4.00
20.00
.00
.00
-2.00
2010
2011
2012
04/04/12
2013
2014
2015
2.19
1.39
2.00
10.00
0.06
2010
2011
2012
15.27
12.23 12.23
15.44 15.34
16.29
17.43
2015
09/28/11
13.2
14,000.00
16.82
-0.39
On-Peak
On-Peak Market
Market Implied
Implied Heat
Heat Rate
Rate -- mmbtu
mmbtu // MWh
MWh
19.59
17.00
2014
-0.94
-4.00
04/04/12
25.00
20.00
-0.87
2013
-2.00
09/28/11
On-Peak
On-Peak Spark
Spark Spread
Spread -- $$ // MWh
MWh
15.00
9.70
10.00
16.86
10,000.00
11.4
11.1
12,000.00
9.7
9.7
9.8
10.5
11.2
10.2
10.4
11.1 10.7
8,000.00
11.79
6,000.00
10.00
4,000.00
5.00
2,000.00
.00
.00
2010
2011
2012
04/04/12
2013
09/28/11
Note: all of the above data shown for Cal 2012 forwards
2014
2015
2010
2011
2012
04/04/12
2013
2014
2015
09/28/11
34
Source: ISI Research
Recent Commodity Price Trends – Ni Hub
ATC
ATC Power
Power Price
Price -- $/
$/ MWh
MWh
45.00
40.00
35.00
30.00
25.00
20.00
15.00
10.00
5.00
.00
PRB
PRB Dark
Dark Spread
Spread -- $$ // MWh
MWh
42.26
39.64
32.18 32.18
36.77
34.04
32.84
29.84
32.17
29.83
33.80
26.20
2010
2011
2012
2013
04/04/12
2014
12.00
10.92
10.33
10.07
9.15
7.97
6.22
2010
2011
2012
2013
04/04/12
2014
2015
09/28/11
On-Peak
On-Peak Market
Market Implied
Implied Heat
Heat Rate
Rate -- mmbtu
mmbtu // MWh
MWh
11.34
10.24
11.24 10.98
11.94
10.71
10.00
7.14
11.7
12,000.00
10,000.00
8.00
11.02
14,000.00
10.67
10.03 10.03
12.87
11.08 11.08
2015
12.93
12.77
17.69
15.38
09/28/11
On-Peak
On-Peak Spark
Spark Spread
Spread -- $$ // MWh
MWh
14.00
20.00
18.00
16.00
14.00
12.00
10.00
8.00
6.00
4.00
2.00
.00
9.3
9.3
10.1
8.7
9.4
10.2
9.1
9.8
9.1
9.5
9.2
8,000.00
6.00
6,000.00
4.00
4,000.00
2.00
2,000.00
.00
.00
2010
2011
2012
04/04/12
2013
09/28/11
Note: all of the above data shown for Cal 2012 forwards
2014
2015
2010
2011
2012
04/04/12
2013
2014
2015
09/28/11
35
Source: ISI Research
Recent Commodity Price Trends – ERCOT Houston
ATC
ATC Power
Power Price
Price -- $/
$/ MWh
MWh
CAPP
CAPP Dark
Dark Spread
Spread -- $$ // MWh
MWh
10.00
60.00
50.00
40.00
46.18
43.06
42.36
37.74
34.50 34.50
49.43
33.66
42.11
39.85
36.01
3.62
4.00
3.62
3.14
2.00
-0.06
20.00
2.25
1.56
0.77
.00
10.00
2010
-2.00
2011
2010
2011
2012
2013
04/04/12
2014
2015
2013
04/04/12
16,000.00
31.41
09/28/11
14.9
14.6
13.5
14,000.00
25.00
22.54
20.07
20.00
16.47
11.92 11.92
24.26
20.53
2015
On-Peak
On-Peak Market
Market Implied
Implied Heat
Heat Rate
Rate -- mmbtu
mmbtu // MWh
MWh
30.00
23.94
2014
-4.63
-6.00
09/28/11
On-Peak
On-Peak Spark
Spark Spread
Spread -- $$ // MWh
MWh
35.00
2012
-2.98
-4.00
.00
15.00
6.19
5.69
6.00
28.12
30.00
8.78
8.00
21.99
12,000.00
10,000.00
17.44
9.8
9.8
10.2
10.9
13.1
10.6
12.8
11.1
11.1
8,000.00
13.00
6,000.00
10.00
4,000.00
5.00
2,000.00
.00
.00
2010
2011
2012
04/04/12
2013
09/28/11
Note: all of the above data shown for Cal 2012 forwards
2014
2015
2010
2011
2012
04/04/12
2013
2014
2015
09/28/11
36
Source: ISI Research
Oil and Gas Prices – ISI Forecasts vs. Futures
Q1 2011
Q2 2011
Q3 2011
Q4 2011
2011
WTI Crude Oil
ISI
Futures
($/Bbl)
($/Bbl)
$94.60
NM
$102.34
NM
$89.54
NM
$89.87
NM
$94.09
NM
Brent Crude Oil
ISI
Futures
($/Bbl)
($/Bbl)
$104.88
NM
$118.40
NM
$112.09
NM
$114.14
NM
$112.38
NM
NYMEX Natural Gas
ISI
Futures
($/MMBtu)
($/MMBtu)
$4.14
NM
$4.36
NM
$4.19
NM
$3.55
NM
$4.06
NM
Q1 2012
Q2 2012
Q3 2012
Q4 2012
2012
$97.00
$97.00
$102.00
$112.00
$102.00
$101.12
$103.44
$102.85
$101.69
$102.28
$105.00
$105.00
$110.00
$120.00
$110.00
$109.71
$110.87
$109.47
$107.98
$109.51
$3.25
$3.75
$4.25
$4.50
$3.94
$3.03
$3.14
$3.28
$3.51
$3.24
Q1 2013
Q2 2013
Q3 2013
Q4 2013
2013
$102.00
$102.00
$102.00
$102.00
$102.00
$100.47
$99.40
$98.23
$97.37
$98.87
$110.00
$110.00
$110.00
$110.00
$110.00
$106.51
$105.11
$103.79
$102.58
$104.50
$5.00
$5.00
$5.00
$5.00
$5.00
$3.87
$3.83
$3.92
$4.11
$3.93
Q1 2014
Q2 2014
Q3 2014
Q4 2014
2014
$104.00
$104.00
$104.00
$104.00
$104.00
$96.29
$95.31
$94.49
$93.80
$94.97
$112.00
$112.00
$112.00
$112.00
$112.00
$101.42
$100.28
$99.28
$98.38
$99.84
$5.00
$5.00
$5.00
$5.00
$5.00
$4.38
$4.23
$4.30
$4.47
$4.34
37
Source: Bloomberg LP, ISI Group E&P Research estimates. Note: Forecasts in blue.
Power Demand Has Recovered From ’09 Trough
•
From 1990 to 2008, total US Electricity demand grew at a CAGR of 1.8%
– 1% below US Real GDP Growth of 2.8%
•
•
Commercial demand has the highest correlation with GDP
Industrial Demand shows a high correlation with Industrial Production
–
Relatively Flat over the same period, with a steep drop in 2009
4,000
3,500
14,000
Residential
Industrial
Commercial
Other
GDP
3,000
12,000
10,000
2,500
8,000
2,000
6,000
1,500
1,000
500
2,000
0
19
90
19
91
19
92
19
93
19
94
19
95
19
96
19
97
19
98
19
99
20
00
20
01
20
02
20
03
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
0
4,000
38
Source: ISI Research
…And Is Back to ’08 Levels, But Comps Will Be Difficult
•
2011 Demand is back to 2008 levels, after a 4% drop from ’08 to ’09 and
2.9% improvement from ’09 to ‘10
•
The South Central region has shown exceptionally strong growth, while the
West and Pacific Northwest have lagged
•
Hot summer and cold winter weather have helped in both 2010 and 2011.
2012 Comps may be challenging
EEI Load Data: U.S. ex Hawaii and Alaska
2011 US Electricity Demand vs. 2010, 2009 and 2008
107,000
-0.7%
New England
-1.2%
Mid-Atlantic
-1.1%
-0.1%
Central Industrial
102,000
2.2%
92,000
4.0%
-0.5%
-5.7%
87,000
1.3%
-4.3%
South Central
-7.5%
-8.0%
-5.1%
-2.3%
4.0%
5.0%
72,000
0.4%
-0.4%
'11 vs. '10
67,000
3.1%
-0.6%
-3.0%
82,000
77,000
0.5%
1.0%
-1.1%
Pacific Northwest
Total US
15.2%
8.6%
3.9%
Rocky Mountain
Pacific Northwest
97,000
4.4%
-1.3%
-2.1%
West Central
Southeast
1.5%
0.7%
62,000
2.0%
'11 vs. '09
7.0%
12.0%
17.0%
Jan
Feb
Mar
Apr
May
Jun
Jul
Sep
Oct
Nov
Dec
'11 vs. '08
39
Source: ISI Research
Weather Driving Lower Demand in the Beginning of ‘12
•
Although we’re only 11 weeks into 2012, cooling degree days and overall
demand are much lower than normal across the US
2012 - Mild weather, and very low demand
2011 - Cold weather, above average demand
EEI Load Data: U.S. ex Hawaii and Alaska
EEI Load Data: U.S. ex Hawaii and Alaska
107,000
107,000
102,000
102,000
97,000
97,000
92,000
92,000
87,000
87,000
82,000
82,000
77,000
77,000
72,000
72,000
67,000
67,000
62,000
62,000
Jan
Feb
Mar
Apr
May
Jun
Jul
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Sep
Oct
Nov
Dec
40
Weather Driving Lower Demand in the Beginning of ‘12
•
Heating Degree Days are down 18.5% thus far in the year, while overall
electric demand is down 4.8%.
U.S. Weekly Electricity Output (GWh)
Region
QTD '12
Quarter to Date
QTD '11
Variance
YTD '12
Year to Date
YTD '11
Variance
New England
Mid-Atlantic
Central Industrial
West Central
Southeast
South Central
Rocky Mountain
Pacific Northwest
Pacific Southwest
27,157
92,389
148,987
67,535
208,573
124,987
52,805
38,276
57,067
28,584
97,337
157,599
73,221
219,195
131,537
53,521
40,253
58,199
-5.0%
-5.1%
-5.5%
-7.8%
-4.8%
-5.0%
-1.3%
-4.9%
-1.9%
27,157
92,389
148,987
67,535
208,573
124,987
52,805
38,276
57,067
28,584
97,337
157,599
73,221
219,195
131,537
53,521
40,253
58,199
-5.0%
-5.1%
-5.5%
-7.8%
-4.8%
-5.0%
-1.3%
-4.9%
-1.9%
Total
817,776
859,446
-4.8%
817,776
859,446
-4.8%
Specific Company Exposures
D, ETR, GEN, NRG, NST, NU, PEG
D, DYN, ED, EXC, FE, GEN, PEG, POM, PPL
AEE, AEP, CMS, DPL, DTE, DUK, DYN, EXC, FE
ALE, GXP, LNT, MDU, XEL, WEC, WR
D, DUK, NEE, PGN, SCG, SO, TE
AEP, CNP, EE, ETR, OGE, NRG, XEL
IDA, NVE, PNM, PNW, XEL
AVA, POR
EIX, PCG, SRE
U.S. Heating Degree Days (HDDs)
Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Total
QTD '12
Quarter to Date
QTD '11
Variance
YTD '12
Year to Date
YTD '11
Variance
2,430
2,179
2,333
2,411
1,075
1,286
857
1,899
1,203
2,921
2,643
2,929
3,135
1,355
1,713
1,199
2,071
1,272
-16.8%
-17.6%
-20.3%
-23.1%
-20.7%
-24.9%
-28.5%
-8.3%
-5.4%
2,430
2,179
2,333
2,411
1,075
1,286
857
1,899
1,203
2,921
2,643
2,929
3,135
1,355
1,713
1,199
2,071
1,272
-16.8%
-17.6%
-20.3%
-23.1%
-20.7%
-24.9%
-28.5%
-8.3%
-5.4%
15,673
19,238
-18.5%
15,673
19,238
-18.5%
Specific Company Exposures
D, ETR, GEN, NRG, NU, PEG
D, DYN, ED, EXC, FE, PEG, PPL
AEE, AEP, CMS, DPL, DTE, DUK, DYN, EXC, FE, WEC
ALE, EDE, GXP, LNT, MDU, XEL, WR
D, DUK, FPL, PEG, PGN, POM, SCG, SO, TE
ETR, SO
AEP, CNL, CNP, EE, ETR, OGE, GEN, TXU, XEL
IDA, NVE, PNM, PNW, XEL
AVA, EIX, PCG, POR, PSD, SRE
41
Supply: Except for ERCOT, Markets Look Well Supplied
Summer 2015 Forecast
•
According to the latest NERC
LTRA, only ERCOT looks to be
falling below its reference reserve
margin by 2015
Summer 2020 Forecast
•
By 2020, New England and PJM
may tighten significantly,
depending critically on
assumptions regarding new
supply / plant retirements
42
Source: NERC 2011 Long-Term Reliability Assessment
But We’re Seeing Coal Retirement Announcements Pick Up
•
•
In response to the challenging commodity price and the anticipation of
Environmental regulations, more coal retirements are being announced
In the past 3 years 30 GW of coal-fired generation (~10% of the US fleet)
has announced plans to retire
Coal Plant Retirement Announcments (MW)
16,000
14,573
14,000
12,000
10,000
8,000
7,560
7,868
2009
2010
6,000
3,236
4,000
2,000
647
21
739
1,039
2002
2003
1,635
1,676
2005
2006
2,622
481
0
2000
2001
2004
2007
2008
2011
YTD
43
Source: ISI Research
Retirements To Date Driven by Weak Coal vs. Gas Spread…
•
•
•
Increased Shale gas production has driven down natural gas prices, while
strong export demand, increased mining costs and more environmental
restrictions have caused eastern coal prices to rise
More expensive to burn coal than natural gas in Eastern markets
Coal units in Eastern markets are running less and making less margin…
Fuel Cost per mmbtu (Adjusted)
$14
$12
$10
$8
$6
$4
$2
$0
Jul-01
Jul-02
Jul-03
Jul-04
PRB
Jul-05
Jul-06
GAS
Jul-07
Jul-08
Jul-09
Jul-10
Jul-11
CAPP
44
Source: FactSet, ISI Research
Southeast & Mid-Atlantic Coal Most Challenged vs Gas
PJM Coal Plants
(NAPP / CAPP)
SERC – CAPP,
Mostly Regulated
45
Source: ISI Utilities Research, NERC, Ventyx
The Mercury Rule Should Impact Energy Markets
•
Energy Market impact of NESHAP won’t be felt until rule is implemented (3
years from Final Rule, or January 2015 under statute)
•
PJM East, West and AD Hub
– Little to no impact on Energy markets for most hours
– Very slight impact on PJM East peak pricing
– Impact on relatively few high-cost peak hours in PJM West
– More significant impact on AD Hub peak prices
•
Significant tightening in NI Hub; Large impact across much of the peak
hours ($8-$30 / MWh)
– Will likely result in the erosion of basis differentials between NI Hub and AD
Hub
•
Cinergy
– Impact more evident across the entire load distribution
– $2 -$6 / MWh across most hours
– >$10 / MWh impact during certain high-priced peak hours
46
The Mercury Rule Should Impact Energy Markets
•
Modeled based on Ventyx Transmission Area
•
Contiguous US, grid-connected plants, excludes on-site capacity, adjusts
wind and hydro capacity
•
Uses 2008 as base year for load histogram
•
Assumes $5.25/mmbtu gas, $100/t delivered bituminous coal, $45/ton
delivered PRB coal, $20/ton delivered lignite and $100/bbl oil / distillate
•
Ignores net transfers (transmission in and out of transmission area)
•
First curve (light blue) reflects current operating capacity, post CSAPR
impact capacity in each region
•
Second curve (dark blue) assumes retirements of coal units that are
– In service prior to 1/1/1970; AND
– Less than 300 MW; AND
– Have no installed SOx Controls
•
Total US coal retirements under those assumptions would be ~75 GW.
•
Announced retirements between now and 2020 at 27.5 GW (see prior
slide)
47
Capacity Market Impact is Key Value Driver
•
Based on current assumptions, we think there is reasonable chance that the ’15 /
’16 BRA clears significantly higher than expectations ($250- $350 /MW day). The
analysis will depend on the auction parameters, which will not be released until
April 2012
•
•
Modeled based on 2014 / 2015 Resource Model
Base Case Assumes
– ‘14 / ‘15 Reliability Requirements
– No units offered under an FRR
– ‘14 / ‘15 Net CONE and VRR demand curve points
– 6,000 MW of Net Imports
– AEP, DUKE, DEOK & DOM units offer at Zero
– All other units offer at allowable ACR less 3 year average Net Energy Margin (based on Ventyx
Unit level data, excluding fixed costs)
– All units (other than DR) offer at pool-wide EFORd of 6.25%
– ‘14 / ‘15 cleared DR bids at $85 / MW day (less than ’14 / ’15 Auction clearing price)
– DR that offered, but did not clear bid at $150 / MW day
Base Case Does Not adjust for
– Bidding Behavior
– APIR Adjustments for environmental retrofits
– Excused Capacity
– New Entry
•
48
‘15 / ’16 PJM Capacity Market Impact
•
Modeled based on 2014 / 2015 Resource Model
•
‘15 / ‘16 Scenario Analysis
•
–
All units with announced retirement dates < 5/31/16 do not offer
–
Uncontrolled coal units < 300 MW, with CODs < 1960 do not offer
–
SO2 controlled coal units (regardless of size / age) DO offer
–
AEP units offer competitively into RPM (ACR less Net Energy Margin + APIR)
–
APIR Adjustments for controls based on 4 categories (Small PRB, Large PRB, Small
CAPP, Large CAPP)
–
Fore each category – Per KW capex assumptions for SOx, NOx, and PM Controls
–
Capital Recovery Factor based on 15 year remaining life
–
DR that offered, but did not clear in ’14 / ‘15 bids at $150 / MW day (3,109 MW)
–
Incremental 10% DR offered at $200 / MW day (1,554 MW)
Model Case Does Not Adjust for
–
Bidding Behavior
–
New Entry
–
Adjustments to Reliability Requirement, VRR or Net CONE
49
PJM Capacity Market Impact - Conclusions
•
•
•
Based on our analysis, the ’15 / ’16 capacity market looks extremely tight
–
Reliability requirement unlikely to be relaxed – Forecast Peak Load already exceeded by
5% in 2011
–
8,300 MW of ICAP with announced retirement dates prior to 5/31/16
–
After adjusting bids for Environmental Capex an additional 6,000 MW of uncontrolled
coal would not clear
–
AEP likely to introduce a net short position into auction
–
DR already represents 10% of peak load
Brattle Report Recommendations do not help;
–
Increase Price Cap of VRR
–
Reduce E&AS offset
–
Elimination of STPT for Annual and Extended Summer resources
–
Stricter measurement and verification of DR
Based on the above, RTO Clearing prices in the $200-$225 range (or higher)
appear reasonable for annual resources
–
Marginal Unit likely to be either high priced demand response or new generation
–
New generation bid price will depend on how the MOPR issue gets resolved
–
PJM market design may determine whether new gas-fired generation or scrubbers get
built (no minimum offer price for retrofits)
50
Our “Open” EBITDA Valuation Approach
•
“Open” refers to the EBITDA that a merchant generator would earn
assuming all of its output is un-hedged, and that it 1) receives the current
forward price for power and 2) pays the current forward price for fuel
•
We base our valuation on 2014 Open EBITDA (Diversifieds & IPP’s are
substantially un-hedged by 2014)
•
Calendar 2014 NYMEX natural gas = $4.67 (at 11/23/11)
•
We derive the “correct” EBITDA multiple by considering the company’s
WACC, and the remaining life of each generation asset in the portfolio
•
Our consolidated EBITDA multiple takes the average of each individual
asset, weighted by its contribution to total Open EBITDA
•
We discount our Merchant generation valuation in 2014 back to one year
from today (at the company’s cost of equity)
51
Source: ISI Research
“Open” EBITDA Multiple Calculation – An Example
EBITDA
EBITDA Multiple
Multiple –– 25
25 Year
Year Remaining
Remaining Life
Life
Capital Structure
Year
Equity
Rf
Eq Rp
Beta
Ke
34%
3.0%
5.4%
1.50x
11.0%
Debt
Rf
Credit Spread
Pre-tax Cost of Debt
Tax Rate
After tax Kd
66%
3.0%
4.5%
7.5%
35.0%
4.9%
WACC
7.0%
Other Assumptions
Inflation
D&A % of EBITDA
Mtce Capex % D&A
Terminal Value
2%
20%
75%
0
Sum of DCF
Year 1 EBITDA
7.98
1.00
EBITDA Multiple
8.0x
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
EBITDA
1.00
1.02
1.04
1.06
1.08
1.10
1.13
1.15
1.17
1.20
1.22
1.24
1.27
1.29
1.32
1.35
1.37
1.40
1.43
1.46
1.49
1.52
1.55
1.58
1.61
Tax
-0.28
-0.29
-0.29
-0.30
-0.30
-0.31
-0.32
-0.32
-0.33
-0.33
-0.34
-0.35
-0.36
-0.36
-0.37
-0.38
-0.38
-0.39
-0.40
-0.41
-0.42
-0.42
-0.43
-0.44
-0.45
Mtce
Capex
-0.15
-0.15
-0.16
-0.16
-0.16
-0.17
-0.17
-0.17
-0.18
-0.18
-0.18
-0.19
-0.19
-0.19
-0.20
-0.20
-0.21
-0.21
-0.21
-0.22
-0.22
-0.23
-0.23
-0.24
-0.24
FCF
0.57
0.58
0.59
0.60
0.62
0.63
0.64
0.65
0.67
0.68
0.69
0.71
0.72
0.74
0.75
0.77
0.78
0.80
0.81
0.83
0.85
0.86
0.88
0.90
0.92
EBITDA
EBITDA Multiple
Multiple –– 10
10 Year
Year Remaining
Remaining Life
Life
Discnted
at WACC
0.53
0.51
0.48
0.46
0.44
0.42
0.40
0.38
0.36
0.35
0.33
0.32
0.30
0.29
0.27
0.26
0.25
0.24
0.23
0.22
0.21
0.20
0.19
0.18
0.17
Capital Structure
Year
Equity
Rf
Eq Rp
Beta
Ke
34%
3.0%
5.4%
1.50x
11.0%
Debt
Rf
Credit Spread
Pre-tax Cost of Debt
Tax Rate
After tax Kd
66%
3.0%
4.5%
7.5%
35.0%
4.9%
WACC
1
2
3
4
5
6
7
8
9
10
EBITDA
1.00
1.02
1.04
1.06
1.08
1.10
1.13
1.15
1.17
1.20
Tax
-0.28
-0.29
-0.29
-0.30
-0.30
-0.31
-0.32
-0.32
-0.33
-0.33
Mtce
Capex
-0.07
-0.07
-0.07
-0.07
-0.08
-0.08
-0.08
-0.08
-0.08
-0.08
FCF
0.65
0.66
0.68
0.69
0.70
0.72
0.73
0.75
0.76
0.78
Discnted
at WACC
0.61
0.58
0.55
0.53
0.50
0.48
0.46
0.44
0.42
0.40
7.0%
Other Assumptions
Inflation
D&A % of EBITDA
Mtce Capex % D&A
Terminal Value
2%
20%
35%
0
Sum of DCF
Year 1 EBITDA
4.95
1.00
EBITDA Multiple
5.0x
Given
Given the
the above
above assumptions,
assumptions, investors
investors should
should be
be willing
willing to
to pay
pay 8.0x
8.0x EBITDA
EBITDA for
for aa plant
plant with
with aa
25
year
remaining
life,
but
only
5.0x
for
a
plant
with
a
10
year
remaining
life.
25 year remaining life, but only 5.0x for a plant with a 10 year remaining life.
*We assume that plants with shorter remaining lives will re-invest less capex as a % of plant D&A
52
Source: ISI Research
Our Proprietary Estimates of “Mid-Cycle” Capacity Pricing
•
For regions with organized capacity markets and a credible tightening thesis, we
determine the price required for a new CCGT to earn a 9% return on equity (given
the assumptions below)
•
For regions without organized capacity markets or regions which lack a credible
tightening thesis, we estimate a $/MW day value which is higher than current
market prices, but less than the new entrant pricing described above
•
The example below shows how we arrive at a $198.63 / MW day Mid-cycle capacity
price for the PJM RTO region.
Key Assumptions
Natural Gas Price $ / mmbtu
Regional Gas Basis
On-Peak Market Heat Rate
On-Peak Power Price
Construction Cost $ / KW
Plant Heat Rate (btu / KWh)
Net Capacity Factor
Variable Operating Cost $ / MWh
Fixed Operating Cost $ / MWh
Maintenance Capex $/ KW Month
Life of Plant (Years)
Tax Rate
Debt to Total Capital
Cost of Debt
Required Equity Return
Calculation of Midcycle Capacity Price
4.67
0.50
10,339
53.50
1,000
7,200
45%
2.50
1.00
0.45
30
Required After Tax Cash Flow / MW 1
Required Net Income / MW
Required EBIT / MW
Required Revenue / MW
Less Expected Energy Revenue
Plus Expected Fuel & Opex
Required Capacity Price $ / MW day
Actual Capacity Price (2014 / 2015)
Required Uplift to Capacity Price
35.0%
50.0%
7.5%
9.0%
Capcity Region
51.8
23.9
81.3
126.7
-210.9
156.7
198.63
-125.99
72.64
Most Recent ISI Est CONE
Valuation
Clearing Price at a 9% Ke Case Override
NE - Rest of Market
NE - Maine
NYC
NY - Rest of State
NY - Long Island
RTO
MAAC
EMAAC
JCPL
DPL South
PSEG
PSEG North
SW MAAC
PEPCO
ATSI
Midwest2
CA Region2,3
105.00
105.00
476.00
15.45
16.75
125.99
136.50
136.50
136.50
136.50
136.50
225.00
136.50
136.50
125.99
30.00
41.00
193.23
193.23
220.03
323.90
190.89
198.63
227.77
170.52
170.52
199.66
170.52
199.66
170.52
199.66
203.39
203.39
259.05
193.23
193.23
300.00
85.00
85.00
198.63
227.77
170.52
170.52
199.66
170.52
199.66
170.52
199.66
203.39
85.00
75.00
Southeast 2
25.00
293.86
50.00
1) After tax cash flow required assumes a 30 year life and a 3 year construction period
2) Regions without organized capacity markets or a credible tightening thesis
3) Represents the Resource Adequacy payment in California
53
Source: ISI Research
Regulated Ratings, Targets & Investment Theses
Ticker
ISI
Rating
Target
Price
Current One Yr
Price
Total Rtn
Summary of Investment Thesis
EIX
BUY
49.00
43.10
16.7%
EIX stock is undervalued in part because consolidated EPS will decline through ’13 due to rising losses at Edison Mission Group. At EMG the LT value proposition
hinges on management’s ability to manage the cash flow/ balance sheet while waiting for improvement in power/capacity markets, and its ability to cost effectively
comply with environmental obligations. Drivers over the next 18 months include resolution of CA regulatory proceedings (rate case & cost of capital proceeding).
WR
BUY
31.50
28.26
16.0%
We think the resolution of WR’s pending base rate case by April 2012 will validate both their near term earnings outlook and a stable regulatory regime, allowing WR
to trade to a higher valuation. WR will grow rate-base at >8% annually between ‘10 and ‘15, with capital committed to environmental retrofits at coal plants and
transmission infrastructure. After equity needs, we expect 5% EPS growth over that period, with the dividend growing in line with earnings.
BUY
53.00
48.11
14.5%
We think the resolution of PNW’s pending rate case settlement in Q2 2012 will validate both their near term earnings outlook and a stable regulatory regime, allowing
PNW to trade to a higher valuation. The settlement should allow PNW a regulatory framework supportive of a reasonable return on current and future capital
investment. With 6-7% rate base growth, a stable earned ROE approaching its authorized return, offset by equity needs in ‘14/’15, we think PNW can achieve a
5.5% earnings CAGR from ’12-’15. The earnings visibility created by the settlement should allow PNW to also grow the dividend at a 3-4% annual rate over the
forecast period.
HOLD
19.50
17.80
14.3%
TECO’s core utilities have only 2.5% growth in rate base expected from ’10-’15. TE has reduced legacy utility investments in Guatemala so their significant nonutility exposure is at TECO Coal. The investment case hinges on: 1) How cash rich they become over the next few years as they consume parent NOL’s and capture
increased profits from met-coal before global supply conditions improve, and; 2) what they do with the money.
PCG
BUY
47.00
43.48
12.3%
The stock has been pummeled by the continued financial overhang from last year’s pipeline explosion, negative EPS revisions for ’12 due to other un-related
headwinds, and increased CA regulatory risk in ’13 due to the increasing certainty of a lower ROE and equity ratio being granted. We think these risks are priced-in,
as PCG has underperformed its peers by ~29% over the past year, trading at 13.5x ’13. The stock appears to discount almost $1.5 billion of value destruction in
excess of our estimate. We think that is extreme.
NVE
HOLD
17.50
16.16
11.3%
NVE’s stock price has risen over the last 18 months as the time approached for the filing of a rate case for their southern Nevada subsidiary, because investors have
become comfortable that the regulatory environment in Nevada is now balanced enough to discount a rational outcome. The stock has upside to an economic
recovery, but appears fully valued under our base case.
NST
HOLD
50.50
47.65
9.6%
Since our launch, NST shares look more rationally priced, having discounted some execution risk on their capital program and the regulatory front. Our forecast
assumes the pending merger between NU and NSTAR closes by YE ’11, so we value NST at 1.312 our $33.50 target price for NU
AEP
HOLD
40.00
38.27
9.3%
The financial outlook has been inscrutable for the last 18 months due to a panoply of regulatory and political uncertainties, particularly in Ohio. We believe the stock
overly discounts the risks. The current price discounts no growth in earnings through 2014 and that the company never breaks a 10% ROE at its core utility
business. As AEP resolves some of the issues or gets more clarity on them over the next 12 months, the risk premium in the stock will dissipate.
NU
HOLD
38.50
36.41
8.8%
Since our launch, NU shares look more rationally priced, having discounted some execution risk on their capital program and the regulatory front. Our forecast
assumes the pending merger between NU and NSTAR closes by YE ’11, increasing NU’s EPS growth potential from ’10-15 to 7% from 6% annually assuming: 1)
They hit transmission development goals, 2) Merger synergies help NU operating subs to earn better ROE’s, and 3) NST negotiates a constructive multi-year rate
deal to replace the one expiring YE ’12.
DUK
HOLD
22.00
21.18
8.5%
The proposed merger with PGN appears value enhancing for DUK shareholders as it creates tangible customer benefits through rate mitigation, while a modest level
of operating synergies retained by the combined company could help Duke’s Carolina and Indiana regulated returns on equity lag less than we had forecasted given
their aggressive cap-ex plan and cost over-run issues. This—among other factors—improves the odds that the combined company will be able to achieve it LT EPS
growth aspiration of 4-6% off 2011 EPS.
PNW
TE
54
Source: FactSet, ISI Research
Regulated Ratings, Targets & Investment Theses
ISI
Rating
Target
Price
DTE
HOLD
58.00
55.98
7.8%
DTE is a bit more diversified than most of its peers. Gas storage/pipelines, an unregulated power and industrial projects unit and energy trading round out the mix.
For DTE to achieve its 5-6% EPS growth target through ’15 DTE will need stable authorized returns in MI and is counting on significant growth at the P&IP unit and
the gas business. We have a hard time betting against DTE as they are sound operators and allocators of capital, but they have a marginally higher risk profile given
the business mix.
XEL
HOLD
27.00
26.71
4.9%
We expect EPS growth to decelerate to 5% through 2015, with dividend growth averaging around 3%. The key to XEL hitting the higher end of its 5-7% EPS growth
aspiration and achieving P/E multiple expansion is showing an improving ROE trend at its core utility business
SRE
HOLD
65.00
64.09
4.3%
SRE is capable of reaching its EPS growth aspiration of 6-8% annually, given rate base growth at its core CA utilities, growth projects at its pipeline and storage
segment, and the contribution from its solar power development pipeline. At a 23% discount to the peer group it appears interesting. However, the earnings expected
to come from investment tax credits (15% by 2015) is an issue, as is increased exposure to South America through buying 100% ownership of utilities in Peru and
Chile.
D
HOLD
51.00
50.81
4.3%
Skeptics look at Dominon’s recent outperformance and high relative P/E versus the peer group and conclude the stock is overvalued. We conclude that this is only
partly true and that a premium is to a large degree justified, driven by the superior return and growth profile of the utility and gas infrastructure segments over the
forecast period.
HE
HOLD
26.00
26.16
4.1%
Risks to our price target include unfavorable ratemaking outcomes in Hawaii which could reduce rate base and earnings growth, and increased credit pressures at
the bank, both of which may make it difficult for the company to fund its capex requirement and maintain the dividend at the current level. Higher interest rates could
pressure net interest margin at the bank.
CMS
HOLD
22.00
22.24
2.7%
In Mid-2010, CMS materially increased the dividend and laid out a capital expenditure program that support EPS growth from ’10-’15 of between 5-7%. This
presumes consistent treatment by the Michigan regulators and an absence of equity financing needs over the forecast period. All in all, CMS has become a lower
risk investment with a balanced total return profile. While CMS offers an EPS and total return profile consistent with other regulated names, the discount is driven to
some degree by its higher leverage/lower credit profile relative to its peers.
WEC
HOLD
35.50
35.84
2.0%
WEC is concluding a seven year infrastructure growth cycle through. The company will be cash rich over the next several years but lacks investment opportunities at
its core utility, so they will return value to shareholders through increasing the dividend payout ratio to 60% over ‘12-’15 and buying back $300m of stock from mid-‘11
through ‘13.
ED
SELL
56.00
58.73
-0.6%
ED’s premium valuation is driven by its inherent “defensiveness” as a conservatively operated, predictable dividend payer with a rate certainty through mid-’13 but
looks overvalued on our base case forecast. We think that ED’s stock will be more influenced short-term by exogenous factors as its defensive premium will
dissipate if U.S. economic conditions improve and the market begins embracing risk.
SO
HOLD
43.50
45.87
-1.1%
Southern has the building blocks in place to achieve the high end of their 5-7% EPS growth aspiration through 2015, while earning an above-industry average ROE
and looks like an execution story over the next 24-36 months, but this largely appears reflected in the stock price.
PGN
SELL
47.00
52.24
-5.3%
The proposed merger with DUK appears value enhancing as it creates customer benefits through rate mitigation, while a modest level of synergies retained by the
combined company could drive less regulatory lag than we had forecasted given their aggressive cap-ex plan and nuclear issue in FL.
Ticker
Current One Yr
Price
Total Rtn
Summary of Investment Thesis
55
Source: FactSet, ISI Research
Diversified Ratings, Targets & Investment Theses
Ticker
EXC
PEG
ISI
Rating
Target
Price
HOLD
46.00
HOLD
34.50
Current One Yr
Price
Total Rtn
37.94
30.40
Summary of Investment Thesis
26.8%
We forecast EPS bottoming in ’12 and rising thereafter due to higher power curves and higher capacity prices. The proposed merger with CEG is accretive to both
NT earnings and LT value. The transaction will generate synergies both from cost savings and revenue opportunities due to a better matching of power market length
with CEG’s load obligations.
18.0%
We forecast stable profits from PEG Power’s 13,538MW portfolio of mainly PJM-based generation, with better capacity and wholesale power prices mitigated by
retail power margins continuing to decline, but at a slower rate. NJ state-sponsored efforts to increase generation supply could mitigate LT upside in capacity
markets and PEG is a price-taker in a market where their retail market share has eroded. At the utility (PSE&G) rate base growth will average 11% from ’11-’13 (and
likely beyond).
CEG
HOLD
42.75
37.23
17.4%
We forecast CEG’s stand-alone EPS bottoming in ’12 due to the roll off of above-market hedges, and rising thereafter with 1) improving power and capacity markets,
2) assumed growth in its competitive supply business, and 3) improvement in BGE’s earned ROE. Near term drivers are CEG’s securing a balanced outcome in the
MPSC merger approval process and limiting the impact of asset divestitures required to mitigate market power concerns. We think merger is accretive to NT
earnings and LT value.
ETR
HOLD
73.00
65.94
15.7%
The key drivers in our scenario analysis at the ETR utilities center around whether their earned ROE stays in line with the current avg. authorized return of +/-10.5%.
At Wholesale, we are focused on VT Yankee and IP2/3 operation (we assume VT Yankee closes in ’12 & 5-years of operation past their license dates for IP2&3), as
well as on underlying power and capacity market dynamics.
PPL
HOLD
30.00
27.27
15.1%
With the acquisition of Kentucky regulated assets in late ’10 and the Central Networks business in the UK in early ’11 (both from E.On), PPL has repositioned itself
as a predominately regulated utility. We forecast 55% of EPS in ’11 coming from the U.S./UK regulated businesses, growing to >75% in ’15 due to rate base growth
and improving ROE’s, coupled with a decline in earnings contribution from PPL’s competitive supply business as above market hedges roll-off.
BUY
50.00
45.93
13.7%
The key swing factor in our forecast is not growth at FE’s regulated utilities or transmission segment. Its earnings prospects hinge on profits at its +/-20,000MWs of
merchant power generation, merger synergies from the integration of Allegheny Energy, and de-leveraging. There is high margin for error, with a $1 change in gross
margin impacting earnings power by $0.15/share.
AEE
HOLD
33.00
31.93
8.2%
We expect earnings to improve at the utility due to more constructive ratemaking, but merchant power’s earnings will decline substantially in ’13 as hedges roll off.
This is concurrent with an $859mm environmental capital budget between ’11-’15 Still, the 5.3% dividend yield looks safe under these conditions, assuming utility
ROE’s improve.
NEE
HOLD
60.00
63.90
-2.7%
We expect NEE to meet its EPS growth aspiration of 5-7% from ’11-’14 through rate base growth at FP&L as they complete nuclear up-rates and modernize their
gas fired generation fleet, while continuing to grow at Energy Resources through investment in wind and solar power generation, offsetting declining margins due to
hedges rolling at their nuke and fossil plants. Bringing these projects to fruition is key to the outlook through ’14, while securing additional growth projects is key to
the outlook longer term.
FE
56
IPPs, Targets & Investment Theses
Ticker
ISI
Rating
Target
Price
Current One Yr
Price
Total Rtn
Summary of Investment Thesis
GEN
HOLD
3.30
1.96
68.4%
Given its high cost of generation, earnings will depend heavily on tighter capacity markets in PJM. If NESHAP is implemented as expected, this is likely to happen.
We are not comfortable, however, with the assumption that higher capacity prices should be permanently capitalized into the valuation of lower-quality assets. We
believe public policy, if not markets, will ultimately drive construction of lower cost generation, keeping a ceiling on capacity pricing. Improving PJM Dark spreads and
higher contract pricing in CA and the Southeast are also significant drivers of long term value.
NRG
BUY
24.50
15.90
54.1%
NRG has the best sustainable FCF yield (15%+ before growth capex) and strongest balance sheet of its IPP peers. It has a diverse business mix of conventional
generation, utility-scale solar, and mass-market retail operations which should serve to reduce earnings volatility. NRG is a highly levered play on longer-term natural
gas fundamentals, but due to its hedging profile, is also somewhat insulated from any potential near term weakness in the gas price. Every $0.50/mmbtu change
equal to $175m of EBITDA upside and $5-6 /sh of value
CPN
BUY
17.00
18.07
-5.9%
CPN's 29 GW fleet is comprised almost entirely new, efficient gas-fired CCGTs and 725 MW of geothermal assets. In 2010, CPN completed a $5.7 Bn balance sheet
restructuring, pushing out all significant maturities to beyond '15, while retaining remarkable flexibility through a generous investment grade covenant package. On
8/23 it announced its first buyback since exiting bankruptcy in 2008. CPN stands to benefit from rising peak power prices and increased power market volatility,
both of which we're likely to see if EPA regulations are implemented as expected.
NA
DYN is a restructuring play, with a call option on improving Midwest power market conditions. We believe that today, under most scenarios, the asset value of the
company is worth less than the face value of the debt. The bulk of the debt, however, is unsecured and does not mature until 2015. Over the past few weeks, mgmt
has been working to reduce the outstanding principal by 1) issuing new 1st lien senior debt and 2) offering to exchange unsec'ds into a new tranche of secured debt
at a discount to face. Given the size of DYN's market cap relative to the existing debt, small % reductions in principal can lead to large potential gains in equity value
(if power market conditions cooperate). Each 10% reduction in face value of DYN's unsec'd debt equals ~$3/ sh of potential equity value.
DYN
HOLD
NA
0.33
57
ISI Disclaimer
ANALYST CERTIFICATION: The views expressed in this Report accurately reflect the personal views of those preparing the Report about any
and all of the subjects or issuers referenced in this Report. No part of the compensation of any person involved in the preparation of this Report
was, is, or will be directly or indirectly related to the specific recommendations or views expressed by research analysts in this Report.
DISCLOSURE: Neither ISI nor its affiliates beneficially own 1% or more of any class of common equity securities of the subject companies
referenced in this Report. No person(s) responsible for preparing this report or a member of his/her household serve as an officer, director or
advisory board member of any of the subject companies. Neither ISI nor its affiliates have any investment banking or market making operations.
At various times these reports mention clients of ISI from whom ISI has received non-investment banking securities related compensation in the
past 12 months.
DISCLAIMER: This material is based upon information that we consider to be reliable, but neither ISI nor its affiliates guarantee its
completeness or accuracy. Assumptions, opinions and recommendations contained herein are subject to change without notice, and ISI is not
obligated to update the information contained herein. Past performance is not necessarily indicative of future performance. This material is not
intended as an offer or solicitation for the purchase or sale of any security.
ISI RATING SYSTEM: Based on stock's 12-month risk adjusted total return; ETR = total expected return (stock price appreciation/depreciation
+ dividend yield)
Buy Low Risk
ETR
Buy Medium
Risk ETR
Buy High Risk
ETR
>+10%
>+15%
>+20%
Hold Low Risk
ETR
Hold Medium
Risk ETR
Hold High Risk
ETR
0% to +10%
-5% to +15%
-10% to +20%
Sell Low Risk
ETR
Sell Medium Risk
ETR
Sell High Risk
ETR
<0%
<-5%
<-10%
ISI has assigned a rating of BUY to 44% of the securities rated as of 3/31/12.
ISI has assigned a rating of HOLD to 53% of the securities rated as of 3/31/12.
ISI has assigned a rating of SELL to 3% of the securities rated as of 3/31/12.
RISK RATING
Our risk ratings are based on an assessment of underlying business mix (regulated vs. merchant), state regulatory risk and
financial strength
58
Source: ISI Research