2011 keybank-Sept-2-2011.pdf

I
Energy
Industry Research
Electric Utilities Quarterly 2Q11

2Q11 Earnings Solid; Modestly Higher on Average

Near Term, We Believe the Sector Provides
Regulated Rate Base Growth and Stable Dividends

Long Term, We Believe the Sector Is Poised for a
Return to Stable Earnings Growth with Economic Recovery

Continued Industry Consolidation Likely

August 26, 2011

Paul T. Ridzon
[phone]
[e-mail]

Timothy Yee
[phone]
[e-mail]

For important disclosures and certifications,
please refer to page 53 of this document.

KeyBanc Capital Markets Inc.,
Member NYSE/FINRA/SIPC
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 2 of 53
August 2011
Contents
Electric Utilities Quarterly 2Q11 .....................................................................................................................................................................................3
2Q11 RESULTS — BY THE NUMBERS...........................................................................................................................................................................3
Earnings Comparison............................................................................................................................................................................4
Earnings Surprises ................................................................................................................................................................................4
Earnings Adjustments............................................................................................................................................................................4
Stock Price Performance.......................................................................................................................................................................5
Weather.................................................................................................................................................................................................6
2Q11 RATINGS AND PRICE TARGET CHANGES ..........................................................................................................................................................7
Rating Changes.....................................................................................................................................................................................7
Price Target Changes............................................................................................................................................................................7
SECTOR OUTLOOK.........................................................................................................................................................................................................7
GROUP INVESTMENT THESIS........................................................................................................................................................................................9
INDUSTRY THEMES ......................................................................................................................................................................................................10
Retreating Commodity Prices and Available Capacity Heat Up Competition.......................................................................................10
Heightened Importance of Regulatory Success...................................................................................................................................11
Comprehensive Energy Reform at an Impasse; EPA Emissions Rules March Forward .....................................................................11
State Renewable Portfolio Standards..................................................................................................................................................12
Stock Performance Divergence Based on Commodity Exposure........................................................................................................14
Japan Nuclear Crisis Highlights Risks to Nuclear Power Industry.......................................................................................................15
New Generation / Transmission Build to Meet Load Growth ...............................................................................................................16
Cost Escalation in New Generation Build............................................................................................................................................16
Fifteen Percent Dividend Tax Rate Extension .....................................................................................................................................17
M&A ACTIVITY ON THE RISE .......................................................................................................................................................................................18
Possible Acquirees..............................................................................................................................................................................18
Cleco Corporation (CNL-NYSE)...............................................................................................................................................................18
NiSource, Inc. (NI-NYSE).........................................................................................................................................................................18
TECO Energy, Inc. (TE-NYSE) ................................................................................................................................................................18
Possible Acquirers...............................................................................................................................................................................18
Dominion Resources, Inc. (D-NYSE) .......................................................................................................................................................18
Entergy Corporation (ETR-NYSE)............................................................................................................................................................18
Southern Company (SO-NYSE)...............................................................................................................................................................18
Recent M&A Activity Update................................................................................................................................................................19
Gaz Metro L.P. and Central Vermont Public Service Corporation............................................................................................................19
Exelon Corporation and Constellation Energy Group, Inc........................................................................................................................19
AES Corporation and DPL Inc..................................................................................................................................................................19
Duke Energy Corporation and Progress Energy, Inc................................................................................................................................19
SHORT INTEREST OVERVIEW .....................................................................................................................................................................................21
PINNACLE WEST CAPITAL CORPORATION (PNW-NYSE) — LOWERING 2011 ESTIMATE DUE TO WEATHER — reprinted from 08/10/2011....23
GREAT PLAINS ENERGY INCORPORATED (GXP-NYSE) — LOWERING ESTIMATES; ANALYST MEETING TAKEAWAYS — reprinted from
08/10/2011..............................................................................................................................................................................................................25
GREAT PLAINS ENERGY INCORPORATED (GXP-NYSE) — WARMING UP TO GXP HEADING INTO ANALYST DAY, INTRODUCING 2013E —
reprinted from 08/04/2011.....................................................................................................................................................................................29
WISCONSIN ENERGY CORPORATION (WEC-NYSE) — 2Q11 SOLID QUARTER, RAISING FY11 ESTIMATE— reprinted from 08/01/2011 ..........32
ENTERGY CORPORATION (ETR-NYSE) — QUICK ALERT: VERMONT YANKEE INJUNCTION DENIED — reprinted from 07/19/2011................35
NISOURCE, INC. (NI-NYSE) — QUICK ALERT: INCREMENTAL SETTLEMENT PROGRESS IN INDIANA — reprinted from 07/13/2011 ...............36
CENTRAL VERMONT PUBLIC SERVICE CORPORATION (CV-NYSE) — QUICK ALERT: CV ACCEPTS GAZ METRO’S MODESTLY HIGHER
OFFER — reprinted from 07/12/2011....................................................................................................................................................................37
PINNACLE WEST CAPITAL CORPORATION (PNW-NYSE) — TAKEAWAYS FROM INVESTOR MEETINGS — reprinted from 07/06/2011 ...........38
NISOURCE, INC. (NI-NYSE) — INVESTOR MEETING TAKEAWAYS — reprinted from 06/22/2011...........................................................................41
PINACLE WEST CAPITAL CORPORATION (PNW-NYSE) — RATE CASE FILING SEEKS TO MAINTAIN CONSTRUCTIVE RATEMAKING —
reprinted from 06/02/2011.....................................................................................................................................................................................43
CENTRAL VERMONT PUBLIC SERVICE CORPORATION (CV-NYSE) — QUICK ALERT: SELLS FOR SIGNIGICANT PREMIUM — reprinted from
05/30/2011..............................................................................................................................................................................................................47
APPENDIX......................................................................................................................................................................................................................48

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 3 of 53
August 2011
Electric Utilities Quarterly 2Q11
INDUSTRY UPDATE
Paul T. Ridzon: [phone] — [e-mail]
Timothy Yee: [phone] — [e-mail]
2Q11 RESULTS — BY THE NUMBERS

Table 1. Earnings Comparison

Company

Ticker 2Q11E 2Q11A 2Q10A
2Q
Change

2011E 2012E
Ameren Corp. AEE $0.66 $0.59 $0.73 (19.2)% $2.35 $2.30
American Electric Power, Inc. AEP $0.75 $0.73 $0.74 (1.4)% $3.15 $3.20
Avista Corp. AVA $0.50 $0.39 $0.46 (15.2)% $1.80 $1.85
CMS Energy, Inc. CMS $0.24 $0.26 $0.26 N/M $1.45 $1.55
Central Vermont Public Service Corp. CV $0.31 $0.19 $0.11 72.7% $1.65 $1.80
Cleco Corp. CNL $0.59 $0.52 $0.56 (7.1)%

$2.35 $2.40
Consolidated Edison, Inc ED $0.54 $0.56 $0.51 9.8% $3.55 $3.70
DPL Inc. DPL $0.50 $0.33 $0.56 (41.1)% $2.40 $2.40
DTE Energy Co. DTE $0.54 $0.65 $0.39 66.7% $3.60 $3.80
Dominion Resources, Inc. D $0.59 $0.59 $0.72 (18.1)% $3.25 $3.35
Duke Energy Corp. DUK $0.32 $0.33 $0.34 (2.9)%

$1.40 $1.40
Entergy Corp. ETR $1.76 $1.76 $1.71 2.9% $6.60 $6.15
Exelon Corp. EXC $0.99 $1.05 $0.99 6.1% $4.10 $3.00
FirstEnergy Corp. FE $0.69 $0.65 $0.77 (15.6)% $3.30 $3.30
Great Plains Energy, Inc. GXP $0.39 $0.31 $0.47 (34.0)% $1.20 $1.50
IDACORP, Inc. IDA $0.62 $0.42 $0.82 (48.8)%

$3.05 $3.00
MDU Resources Group, Inc. MDU $0.21 $0.24 $0.26 (7.7)% $1.30 $1.45
NextEra Energy, Inc. NEE $1.09 $1.18 $1.11 6.3% $4.45 $4.70
NiSource, Inc. NI $0.17 $0.17 $0.11 54.5% $1.30 $1.45
Northwestern Corp. NWE $0.29 $0.30 $0.23 30.4% $2.35 $2.45
PPL Corp. PPL $0.55 $0.45 $0.62 (27.4)%

$2.60 $2.50
Pepco Holdings, Inc. POM $0.33 $0.42 $0.34 23.5% $1.20 $1.30
Pinnacle West Capital Corp. PNW $0.83 $0.78 $0.83 (6.0)% $2.85 $3.35
Progress Energy, Inc. PGN $0.64 $0.71 $0.63 12.7% $3.10 $3.20
Southern Company SO $0.66 $0.71 $0.62 14.5% $2.55 $2.70
TECO Energy, Inc. TE $0.35 $0.36 $0.37 (2.7)%

$1.35 $1.50
Wisconsin Energy Corp. WEC $0.38 $0.41 $0.37 10.8% $2.15 $2.30
Xcel Energy Inc. XEL $0.31 $0.33 $0.29 13.8% $1.70 $1.80
Average (3.3)%

Source: KeyBanc Capital Markets Inc. and Company reports
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 4 of 53
August 2011
EARNINGS COMPARISON
Overall, companies within our electric utilities coverage universe reported mixed to slightly lower 2Q11 results, as power prices
pressured merchant generator margins, a wet and mild spring with flooding in the Midwest reduced electric demand and increased
O&M storm costs, utilities generally saw higher property taxes and many local economies were still sluggish on retail load growth. As
indicated in Table 1, aggregate 2Q11 earnings for stocks in the KeyBanc Capital Markets Inc. Electric Utility Index were down 3.3% on
average, compared to the same quarter a year ago. Based on our estimates, we had initially anticipated average quarterly earnings of a
slight 0.8% decline, so 2Q11 results were below our expectations, largely due to merchant generation margins, weather and tax items.

EARNINGS SURPRISES
On an individual company basis, there were two notable upside surprises and five notable downside surprises relative to our
expectations for the quarter. On the upside, Exelon Corporation (EXC-NYSE; $1.05 vs. $0.99 in 2Q10; our estimate was $0.99,
consensus was $0.97) beat expectations mostly on tax benefits from transferring nuclear decommissioning funds. Southern Company
(SO-NYSE; $0.71 vs. $0.62 in 2Q10; our estimate was $0.66, consensus was $0.64) beat expectations on higher rates and favorable
weather.

On the downside, Avista Corporation (AVA-NYSE; $0.39 vs. $0.46 in 2Q10; our estimate was $0.50, consensus was $0.48) missed
expectations as higher O&M and low regional wholesale prices more than offset strong hydroelectric generation. DPL Inc. (DPL-NYSE;
$0.33 vs. $0.53 in 2Q10; our estimate was $0.50, consensus was $0.52) results were below expectations due to lower retail and
wholesale margins (in part due to customer switching) and higher O&M expenses from outages. IDACORP, Inc. (IDA-NYSE; $0.42 vs.
$0.82 in 2Q10; our estimate was $0.62, consensus was $0.59) missed expectations on higher O&M costs, higher tax rates and reduced
irrigation load due to wet weather. PPL Corporation (PPL-NYSE; $0.45 vs. $0.62 in 2Q10; our estimate was $0.55, consensus was
$0.48) had earnings below views, primarily due to lower wholesale electricity margins, an extended nuclear outage and share dilution,
partly offset by new regulated rates. Lastly, Cleco Corporation’s (CNL-NYSE; $0.52 vs. $0.56 in 2Q10; our estimate was $0.59,
consensus was $0.63) results were below our expectations as hot weather drove the Company into an over-earning position, forcing a
refund accrual.

As highlighted in our 2Q11 quarterly earnings preview, we correctly predicted one earnings upside and three earnings downside
surprises relative to consensus expectations as NiSource, Inc. (NI-NYSE; $0.17 vs. $0.11 in 2Q10, our estimate was $0.17, consensus
was $0.14) beat to the upside and CMS Energy Corporation (CMS-NYSE; $0.26 vs. $0.26 in 2Q10; our estimate was $0.24, consensus
was $0.27), Northwestern Corporation (NWE-NYSE; $0.30 vs. $0.23 in 2Q10; our estimate was $0.29, consensus was $0.32), and
Pinnacle West Capital Corporation (PNW-NYSE; $0.78 vs. $0.83 in 2Q10; our estimate was $0.83, consensus was $0.87) all had
earnings below consensus expectations.

EARNINGS ADJUSTMENTS
Heading into the 2Q11 earnings reporting season, we raised our 2011 estimate for Southern Company to $2.55 from $2.50 per share
for a modestly improving economy and favorable weather. We raised our 2011 and 2012 estimates by $0.05 for Ameren Corporation
(AEE-NYSE) to $2.35 and $2.30 per share (from $2.30 and $2.25 per share, respectively), adjusting for a recent rate increase granted
in Missouri. We lowered our 2011 estimate for MDU Resources Group, Inc. (MDU-NYSE) to $1.30 from $1.35 per share for severe
weather-related impacts at the E&P segment. We also reduced our 2011 estimate for NextEra Energy, Inc. (NEE-NYSE) to $4.45 from
$4.50 per share for lower unregulated merchant margins.

After digesting 2Q earnings reports, earnings conference calls and investor/analyst meetings, we further revised some earnings
estimates for the upcoming year. We raised our 2011 estimate for Wisconsin Energy Corporation (WEC-NYSE) to $2.15 from $2.08
per share for solid year-to-date results and hot summer weather (see page 32 for our August 1, 2011 published report titled “WEC:
2Q11 Solid Quarter, Raising FY11 Estimate”). We lowered our 2011 estimate for Pinnacle West Capital Corporation to $2.85 from
$3.00 per share primarily for the impact of mild weather and higher property taxes (see page 23 for our August 10, 2011 published
report titled “PNW: Lowering 2011 Estimate Due to Weather”). Following its Analyst Meeting, we also adjusted our 2011, 2012 and
2013 estimates for Great Plains Energy Incorporated (GXP-NYSE) to $1.20, $1.50 and $1.65 per share, from $1.35, $1.60, and $1.70
per share, respectively (see page 25 for our August 10, 2011 published report titled “GXP: Lowering Estimates; Analyst Meeting
Takeaways”).

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 5 of 53
August 2011

STOCK PRICE PERFORMANCE
As shown in Table 2, stock price performance during 2Q11 for companies under coverage in the KeyBanc Capital Markets Inc. Electric
Utility Index was strong, with the index showing 9.0% price appreciation on average. During the quarter, small-cap utility stocks
outperformed as smaller utilities were eyed as prime takeover candidates. In fact, both Central Vermont Public Service Corporation
(CV-NYSE) and DPL Inc. announced during 2Q11 that they had been acquired and their share prices now trade accordingly around
their offer prices. Larger-cap utility stocks managed to deliver solid positive returns during the 2Q as investors began to seek defensive
names in an uncertain economy toward the end of the quarter. Our coverage group’s performance was ahead of the Philadelphia Utility
Index (UTY), which was up 5.1% in 2Q11, and our sector outperformed the broader S&P 500 Index (SPX), which was slightly up 0.4%
for the quarter. This outperformance was driven by two acquisitions. CV and DPL. 2Q11 earnings reports continued to show modest
signs of U.S. economic recovery, with cautious forecasts of load growth in the latter half of 2011. Year-to-date, our sector index price
performance of a 4.0% gain (UTY) has outperformed a loss of 7.6% in the broader market (SPX). We attribute recent sector strength
and outperformance to investors becoming defensive while assessing the global issues with respect to sovereign debt and economic
growth.
Table 2. Price Performance

Price Price Price Price 2Q11 8/23/11
Company Ticker 12/31/10 3/31/11 6/30/11 8/23/11 Change YTD Change
Ameren Corp. AEE 28.19 28.40 28.84 28.88 1.5% 2.4%
American Electric Power, Inc. AEP 35.98 36.23 37.68 37.54 4.0% 4.3%
Avista Corp. AVA 22.52 20.88 25.69 24.02 23.0% 6.7%
CMS Energy, Inc. CMS 18.60 18.02 19.69 19.18 9.3% 3.1%
Central Vermont Public Service Corp. CV 21.86 20.17 36.15 35.07 79.2% 60.4%
Cleco Corp. CNL 30.76 29.62 34.85 33.81 17.7% 9.9%
Consolidated Edison, Inc. ED 49.57 48.22 53.24 55.38 10.4% 11.7%
DPL Inc. DPL 25.71 26.13 30.16 30.00 15.4% 16.7%
DTE Energy Company DTE 45.32 45.93 50.02 48.94 8.9% 8.0%
Dominion Resources, Inc. D 42.72 43.66 48.27 49.10 10.6% 14.9%
Duke Energy Corp. DUK 17.81 17.71 18.83 18.49 6.3% 3.8%
Entergy Corp. ETR 70.83 76.53 68.28 62.36 (10.8)% (12.0)%
Exelon Corp. EXC 41.64 42.58 42.84 42.23 0.6% 1.4%
FirstEnergy Corp. FE 37.02 38.54 44.15 42.53 14.6% 14.9%
Great Plains Energy, Inc. GXP 19.39 18.90 20.73 18.55 9.7% (4.3)%
IDACORP, Inc. IDA 36.98 35.92 39.50 36.37 10.0% (1.6)%
MDU Resources Group, Inc. MDU 20.27 19.95 22.50 20.67 12.8% 2.0%
NextEra Energy, Inc. NEE 51.99 54.39 57.46 55.12 5.6% 6.0%
NiSource, Inc. NI 17.62 17.40 20.25 20.33 16.4% 15.4%
NorthWestern Corp. NWE 28.83 28.50 33.11 32.27 16.2% 11.9%
PPL Corp. PPL 26.32 27.23 27.83 27.61 2.2% 4.9%
Pepco Holdings, Inc. POM 18.25 18.60 19.63 18.86 5.5% 3.3%
Pinnacle West Capital Corp. PNW 41.45 41.27 44.58 42.53 8.0% 2.6%
Progress Energy, Inc. PGN 43.48 44.42 48.01 47.37 8.1% 8.9%
Southern Company SO 38.23 37.24 40.38 40.62 8.4% 6.3%
TECO Energy, Inc. TE 17.80 17.32 18.89 17.59 9.1% (1.2)%
Wisconsin Energy Corp. WEC 29.43 28.90 31.35 31.02 8.5% 5.4%
Xcel Energy Inc. XEL 23.55 22.97 24.30 24.06 5.8% 2.2%
KBCM Electric Utility Index Average 9.0% 6.5%

Benchmarks:
Philadelphia Utility Index UTY 421.84 426.24 447.79 431.24 5.1% 4.0%
S&P 500 Index SPX 1257.64 1325.83 1320.64 1,123.82 (0.4)% (7.6)%
Note: Past results cannot and should not be viewed as indicators of future performance.
Source: Thomson Financial
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 6 of 53
August 2011
WEATHER
By our weather-tracking estimates, much of the nation experienced milder temperatures in 2Q11 (fewer cooling degree days) compared
to the same quarter a year ago. Nationally, heavier than normal precipitation helped keep many regions cool and prolonged the
snowmelt, benefitting hydroelectric generation resources in the Northwest, while a wet spring and frequent storms were experienced in
the mid-Mississippi Valley, Great Plains and Ohio Valley areas. The South and Southeast, however, saw higher temperatures, with
drought-like conditions in Louisiana, New Mexico and especially Texas.

Table 3 shows the impact of the weather temperatures (primarily on retail delivery) in the quarter compared to our predictions.

Table 3. 2Q11 Weather Impact — Cooling Degree Days

Company Ticker
2Q11 vs.
Normal
2Q11 vs.
2Q10
Estimated
Same Qtr YOY
EPS Impact
Actual
Same Qtr YOY
EPS Impact
Ameren Corp. AEE 30.5 % (14.2)% ($0.04) ($0.05)
American Electric Power, Inc. AEP 40.9 % (2.5)% ($0.02) $0.01
Avista Corp. AVA *21.0% *8.9% $0.01 N/A
Cleco Corp. CNL 41.3 % (0.1)% $0.04 $0.01
Dominion Resources, Inc. D 56.6 % (8.5)% ($0.02) ($0.06)
Duke Energy, Inc. DUK 29.7% (13.0)% ($0.01) ($0.01)
Exelon Corp. EXC 26.2 % (21.2)% ($0.01) ($0.01)
Great Plains Energy GXP 24.1 % (11.0)% ($0.04) ($0.02)
Northwestern Corp. NWE *18.3% *15.9% $0.02 N/A
Pepco Holdings, Inc. POM 73.3 % (6.3)% ($0.01) ($0.01)
Pinnacle West Capital Corp. PNW 10.9 % 8.7 % $0.02 ($0.02)
Southern Company SO 40.9 % 4.0 % $0.01 $0.01
(20.6)% (39.6)%
Wisconsin Energy Corp. WEC
*1.7% *55.7%
$0.00 ($0.01)
Xcel Energy, Inc. XEL 12.0 % (3.8)% ($0.01) $0.00
N/A – not readily available from company data
* Data is Heating Degree Days
Sources: National Oceanic and Atmospheric Administration (NOAA), KeyBanc Capital Markets Inc. estimates, and Company reports
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 7 of 53
August 2011

2Q11 RATINGS AND PRICE TARGET CHANGES
RATING CHANGES
During 2Q11, we downgraded IDACORP to HOLD from BUY on May 10, 2011 (see our previously published report titled “IDA: Price
Target Surpassed; HOLD Rating Now Appropriate”).

Our current research for companies under coverage published since our 1Q11 Electric Utilities Quarterly through the date of this
publication is provided on pages 23-47.

PRICE TARGET CHANGES
We regularly revisit and adjust our price targets on BUY-rated stocks given changes in peer group average P/E multiples and our
business and economic outlook. Our current price targets on all of our BUY-rated stocks under coverage are outlined in Table 4.

Table 4. Price Target Changes

Symbol
Current
Rating
Current
Target
Previous
Rating
Previous
Target

Date Changed
AEP BUY $40.50 BUY $38.00 05/27/2011
CMS BUY $21.50 BUY $19.50 05/27/2011
CNL BUY $36.00 BUY $33.00 03/24/2011
MDU BUY $24.00 BUY $26.50 02/07/2011
Source: KeyBanc Capital Markets Inc.

SECTOR OUTLOOK
In the near to intermediate term, we expect investors will be cautious of the group, as several factors are likely to present valuation
overhangs until investors get clarity on the timing of a more robust economic recovery and direction on national comprehensive energy
policies. Industry response to forthcoming EPA environmental regulations has been varied depending on each company’s generation
portfolio asset and fuel mix, environmental controls already in place and potential capital spend required for compliance. In light of the
nuclear power disaster in Japan, we believe investors have taken somewhat of a more cautious approach toward valuing unregulated
U.S. nuclear generators for potential exposure to additional compliance costs or relicensing risks, although stocks for nuclear
generators have rebounded to pre-disaster levels. That being said, given current market volatility driven by concerns around economic
growth, we believe that names offering liquidity, yield and constructive regulation are likely to benefit from defensive portfolio positioning
until markets have calmed.

A slow economy back in 2009 impacted electricity sales and pricing, as industrial customers saw reduced demand for their products
and residential/commercial customer classes adjusted their spending accordingly. 2010 year-end results showed continued modest
signs of the economy stabilizing with generally improving electricity sales comparables to the same periods a year ago, particularly for
the industrial customer classes. 1H11 continued the trend of flat to modest growth. We remain guarded in our near-term outlook,
however, as 2Q11 earnings conference calls cautioned slow to moderating load growth in 2H11 given unemployment and the delicate
state of the economy.

Much of the intermediate to long-term growth in the sector is tied to large capital growth programs earning regulated returns. During a
prior period of lofty valuations and easy credit, investors viewed these programs positively. Recent market performance has made the
equity financing of these large projects less attractive. Names within our group of covered companies that have focused strategies on
rate base growth (not including current projects) include: Ameren Corporation, CMS Energy Corporation, Dominion Resources, Inc. (D-
NYSE), DTE Energy Company (DTE-NYSE), Duke Energy Corporation (DUK-NYSE), NorthWestern Corporation, Pepco Holdings, Inc.
(POM-NYSE), Progress Energy, Inc. (PGN-NYSE) and Xcel Energy Inc. (XEL-NYSE).

In 2010 we saw a large number of new bond issuances, long-term refinancing and the terming out of higher cost short-term debt by
utilities attempting to take advantage of record low long-term Treasury rates. The compression of stock price valuation multiples in the
sector has also negatively impacted the equity financing of capital expenditures, as some names are trading below book value. Credit
and liquidity concerns drove many companies to revisit capital spending plans and reassess operational efficiencies. The primary
response has generally been to delay projects, as opposed to outright cancellation. Initially, reductions in capital programs were a
function of lower growth, which eliminated the need for growth-related capital spending on items such as line extensions and new
substations. However, as challenging economic conditions persist, the cuts have grown more extensive, with deferrals in non-core
maintenance spending, re-evaluating the cost-effectiveness of running older inefficient power plants and pursuing company
restructurings or mergers.

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 8 of 53
August 2011
After outperforming the S&P 500 in the five years preceding 2009, the electric utility sector underperformed the market in 2009 and
2010. We believe the underperformance started with the 4Q08 earnings reporting season, as dividend cuts and conservative earnings
guidance highlighted greater risk than was previously factored into the sector. Consumer electric conservation efforts and economic
pressures affecting customer volumes and margins, low commodity pricing, increasingly populist regulatory sentiment and political
uncertainty around carbon and taxes weighed on our sector throughout 2010.

We expect the group’s stock performance in 2011 will be a function of three primary drivers: commodity pricing, the economy and
environmental compliance costs/risks. Retreating high commodity prices weigh most heavily on unregulated generators with nuclear
assets and coal-fired plants (with firm intermediate to long-term coal contracts). Low natural gas prices driven by low electric power
demand and increasing shale gas supplies should continue to keep wholesale electricity prices at a depressed level, further
exacerbating the margin woes for unregulated generators. In our view, the companies with the most leverage to unregulated
commodity pricing are American Electric Power Company, Inc. (AEP-NYSE), Dominion Resources, Inc., Entergy Corporation (ETR-
NYSE), Exelon Corporation, FirstEnergy Corp. (FE-NYSE), NextEra Energy, Inc. and PPL Corporation. Signs of a stronger
fundamental economic recovery in 2011 or beyond, however, could lift earnings prospects and price multiples for our entire sector, as
evidenced by a rebound for exposed stocks in May 2011 after PJM’s RPM base residual auction results for the 2014-2015 delivery year
generally came in stronger than expected in the Western pricing zone. Weaker Eastern pricing appeared to have a dampened effect.
Finally, forthcoming EPA environmental regulations and the Japanese nuclear crisis have led to an increased focus on potential
additional compliance costs. We believe how the power industry responds to new regulations with the public, regulators and politicians
will drive stock movement.
Chart 1. YTD Performance of UTY vs. SPX
(December 31, 2010 – August 22, 2011)

Jan Feb Mar Apr May Jun Jul Aug
-10
-5
0
5
10
UTY vs. S&P 500
Indexed Price Performance - YTD Return %
S&P 500 (SPX)
PHLX / Utility (UTY)

Source: FactSet

As fears of a double-dip recession were somewhat alleviated before the end of 2010, our industry appeared to fall out of favor as
investors rotated out of the sector in early 2011 in pursuit of higher growth companies in a modestly improving economy. The
Japanese nuclear crisis gave pause to investors in assessing the impact to the global economic recovery, leading to severe declines in
mid-March 2011 for both our sector and the broader market. As companies generally reported in line 1Q earnings with still sluggish
economies, there appeared to be some movement in May 2011 back toward defensive industries such as utilities. This pattern held
true into July with generally in line 2Q earnings reports for our sector prior to the entire market falling on fears of a double-dip U.S.
recession and European sovereign debt. For the year, the sector index (UTY) has recovered to a 4.0% gain, outperforming the 7.6%
loss in the broader market (SPX).

From a 2012 P/E perspective, the group now trades at a 13.6x P/E multiple, compared to an 11.3x P/E multiple on the S&P 500 index.
On a relative basis, the group is around a 20% premium to the S&P 500, compared to more historical discounts of 25-30%. We believe
this divergence is possibly due to investors defensively parking money back into the group while there is concern over a slower global
economic recovery. We believe our sector’s current premium valuation could rapidly converge closer to the S&P 500 P/E multiple
again if investors have broader market confidence in a robust U.S. economy, driving investment into other sectors with greater potential
upside in a more normal economy.

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 9 of 53
August 2011
Chart 2. Price Performance of S&P Electric Companies and 30-Year Treasury Bond Yield

(December 31, 1996 – August 22, 2011)

Source: FactSet

Chart 2 is provided to show historical price performance of S&P electric companies compared to the 30-year Treasury bond yield.
Relative to treasuries, the utilities sector offers a more attractive yield of 4.4% on average, which appears to support an attractive safety
play when needed. Our discussions with investors in 2010 when there was talk of a potential “double dip” seems to confirm this market
dynamic and was evidenced again in July 2011 as the broader market fell, while utilities were impacted to a much lesser extent.

GROUP INVESTMENT THESIS
Broadly speaking, we believe the long-term fundamentals in the electric utility sector remain essentially intact, as opportunities exist in
tight power markets (with an outlook for pricing to improve as the economy recovers and EPA regulations force some level of plant
retirements and the potential to rate base needed capacity) needing to modernize aging transmission and distribution infrastructure,
meet more environmentally friendly portfolio standards and serve growing demographics. We are generally more conservative in our
long-term growth projections, as the sector historically lags and experiences lower demand growth compared to the broader market.

In an industry that must continue to spend money to make money, regulatory risk is ever present as recovery of capital investment is
never 100% assured and companies must seek advanced or later regulatory blessing on large capital expenses to ultimately recover
their costs and earn a return on investment once the asset is placed into service. Our concern is that, at some point, rising electricity
prices will draw enough political attention that regulators will be pressured to ease the sting on ratepayers, putting the shareholder at
risk. We believe the levers in the regulatory toolbox that may be pulled to lower rates include reassessing allowable returns on equity,
extending depreciation rates, reviewing costs of debt and reassessing appropriate capital structure. These negative regulatory
outcomes had precedence in the 1970s, as high oil pricing and continued nuclear cost overruns prompted regulators to force
shareholders to feel some of the pain. Additionally, U.S. nuclear energy is likely to be further impacted by increased scrutiny and
inspections as a result of the recent Japan nuclear crisis.

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 10 of 53
August 2011
The confluence of several factors highlighted below leave us concerned about increasing regulatory risk impacting the sector in the
coming years. These factors include:
· Potential for Populist Regulatory Sentiment. We believe investors must heighten awareness to political and regulatory risk
as higher electricity (and overall energy) pricing becomes more scrutinized, especially during periods of a weak economy. We
view electricity pricing as being far more exposed to local politics than the pricing of other energy commodities, and there are
always risks to timely and fair recovery of investment dollars, despite prior precedents or assurances.
· Environmental Capital Expenditures. On a consolidated basis, the sector must spend tens of billions of dollars to meet
more stringent environmental regulations that can be subject to changing political winds.
· Aggressive Rate Base Growth as an Earnings Driver. Given the low organic growth inherent in the sector, we believe
some players may look for a tailwind by growing the rate base as aggressively as possible.
· Additional Cost Pressure Driven by Inflation. We believe a weak dollar and long-term global competition for infrastructure
materials have increased the rate risk on the proposed capital spend, as projects have an ever-escalating price tag.
· Potential for Continued Low Interest Rates. We believe regulatory risk is increased by low treasury yields, as state
regulatory commissions often use a spread over treasuries as an indicator of appropriate equity return levels.

To some degree, our concerns are longer-dated as the confluence of regulatory risk factors highlighted above needs time to
accumulate. In the short term, we believe that necessary infrastructure investments should and will be encouraged by regulators. More
recently, however, the U.S. economic recession has provided support for our more cautious view as evidenced by politicization of past
rate case proceedings in Florida for NextEra Energy and Progress Energy. We emphasize that investors should monitor local
regulation impacting investments for any move toward restrictive outcomes. Chart 3 illustrates the longer-term trend toward lower
regulated utility equity returns authorized by state Commissions.
Chart 3. Average Authorized Equity Returns
9.00%
10.00%
11.00%
12.00%
13.00%
19
9
0
19
9
1
19
9
2
19
9
3
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
Year
RO
E
%
Electric Gas

Source: Regulatory Research Associates

INDUSTRY THEMES
RETREATING COMMODITY PRICES AND AVAILABLE CAPACITY HEAT UP COMPETITION
Natural gas pricing, remaining stubbornly in a thin trading band, continues to drive the marginal clearing price of power in wholesale
markets (see Chart 4). Given available capacity and the sharp decline in wholesale power pricing as natural gas prices remain low, we
remain vigilant over the potential for competitive marketers to undercut pricing in deregulated markets, such as Ohio and Pennsylvania,
as utilities had previously procured supply during periods of significantly higher pricing. We believe competitive marketers could lock in
supply at current low pricing to offer customers a more attractively priced alternative.
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 11 of 53
August 2011
Chart 4. Comparison of Spot, 12-Month and 24-Month Natural Gas Prices
(December 31, 2004 – August 23, 2011)

$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
$11
$12
$13
$14
$15
$16
De
c
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6
Ma
r
-
0
7
Ju
n
-
0
7
Se
p
-
0
7
De
c
-
0
7
Ma
r
-
0
8
Ju
n
-
0
8
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p
-
0
8
De
c
-
0
8
Ma
r
-
0
9
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n
-
0
9
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p
-
0
9
De
c
-
0
9
Ma
r
-
1
0
Ju
n
-
1
0
Se
p
-
1
0
De
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-
1
0
Ma
r
-
1
1
Ju
n
-
1
1
Se
p
-
1
1
Date
$/
M
M
B
T
U
Spot 12 Mo 24 Mo

Source: Bloomberg

HEIGHTENED IMPORTANCE OF REGULATORY SUCCESS
The major focus of many utilities over the past few years has been the “back-to-basics” approach, through which non-strategic
businesses were divested or shuttered, and the business focus returned to the core utility operations. While this scenario has done a
great deal to mitigate risk and exposure to volatile market conditions, future growth plans have also come into focus. In the past,
companies had pursued diversified opportunities to provide additional growth to offset slower growth in the regulated business. In this
new era of focus on the core regulated utility, the importance of regulatory success has come back to the forefront. Companies that are
able to craft innovative solutions to issues, such as quick recovery of environmental expenditures, will likely set the stage for future
growth of the regulated business. We believe the companies that currently have high levels of exposure to regulatory developments
are Ameren, American Electric Power, CMS Energy, DTE Energy, Exelon, IDACORP, Pepco Holdings and Xcel Energy. We believe a
return of high fuel/commodity and construction materials pricing will likely increase regulatory risk, as regulators seek ways to minimize
the increases in overall customer electric bills, even at the expense of the shareholder.

COMPREHENSIVE ENERGY REFORM AT AN IMPASSE; EPA EMISSIONS RULES MARCH FORWARD
Despite several legislative bills offered over the past several years, we believe that comprehensive energy reform [carbon cap-and-
trade, climate change, federal Renewable Portfolio Standards (RPS), renewable energy qualifying sources and proposals such as
offshore drilling to lessen the U.S. reliance on foreign oil] is unlikely to gain passage under the 2011 Congress. An outlook for continued
slow economic recovery is likely to prevent the issue from gaining traction over the next few years, in our view. We do believe there
might be renewed attempts in Congress to legislate, restrict or delay EPA authority or funding to regulate greenhouse gases, including
carbon, although overriding a Presidential veto would prove difficult.

In the near term, EPA continues to march forward with rulemaking on a host of pollution criterion under the Clean Air Act and Clean
Water Act. For more background and analysis of EPA regulations in 2011 that bear watching, please see our February 22, 2011
published comprehensive report titled “A Review of EPA Regulations Concerning the Electric Power Industry”. Meaningful uncertainty
remains around timelines and how aggressively environmental regulations will be implemented, and we believe the dynamic of how the
Congress, the EPA and the industry work together is something to watch.

We feel it is still important for electric utility investors to become aware of the renewable energy resources available to each utility in
each state, consider the business impact as to how an investor-owned utility would address any state mandates or renewable
standards, and understand the possible implications (favorable and unfavorable) that a potential federal RPS, EPA mandate or other
energy/climate-related (carbon) legislation, if enacted, may have on their utility investments.
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 12 of 53
August 2011
STATE RENEWABLE PORTFOLIO STANDARDS

Thirty-five states and the District of Columbia have adopted state RPSs to foster electricity investments in
efficiency and renewable resources. The result is a patchwork of different state standards on several
factors, including: the ultimate amount or level to be targeted, how to measure the initiative (percent of
capacity installed vs. generation output), timeline for implementation, balance between renewables usage
vs. gains from efficiency, which renewable resources are to be included in the RPS and even whether the
targets being set are voluntary or mandatory.

In Table 5, every state with a date listed has adopted an RPS into law. Five states (North Dakota, South
Dakota, Utah, Vermont and Virginia) have set voluntary renewable portfolio goals instead of a mandatory
target. Since 2009, the Florida legislature has not yet ratified RPS draft rules for 20% renewable
generation by 2020. Currently, Louisiana has a pilot renewable program targeting 350 MW of renewable
capacity by the 2012-2013 time frame. Also, Indiana has a voluntary RPS standard requiring 10% of
energy to be from renewables by 2025.
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 13 of 53
August 2011
Table 5. State Renewable Portfolio Standards

State
original RPS law
adoption date
Amt Year Comments State
original RPS law
adoption date
Amt Year Comments
Arizona
2/26/06 15% 2025
2.5% of total electricity sold from renewable energy sources by 2010 and 15% by
2025. 5% of the renewables to come from solar power in 2007, and will ramp up to
a 30% "distributed" energy technology requirement by 2011. Renewable energy
from facilities installed before 1/1/1997 are not eligible.
New Hampshire
5/11/07 25% 2025
25% of state's electricity from renewable resources by 2025 (includes wind, solar,
geothermal, hydrogen fuels, methane gas, ocean-generated, biomass, and existing
small hydroelectric sources).
California
9/12/02 33% 2020
Renewable energy resources include biomass, solar thermal, photovoltaics, wind,
geothermal, small hydropower, and ocean-generated power. On 9/15/09 the
Governor signed an executive order increasing the original requirement of 20% by
2010 to 33% by 2020. On 3/29/11, the California Assembly passed Senate-
approved bill X1-2 establishing the 33% by 2020 standard into law rather than
relying on California Air Resources Board regulations.
New Jersey
2/9/99 22.5% 2021
AB 3520 on 1/17/10 required 5,316 MW to be generated from in-state solar
generators by 2025. SB 2036 on 8/19/10 is nation's first carve-out offshore wind
requirement calling for 1,000 MW of capacity, details TBD. Resources include solar,
wind, wave, tidal, geothermal, landfill methane gas, fuel cells from renewable fuels,
anaerobic digestion of food waste and sewage sludge at a biomass generating
facility, and hydropower.
Colorado
11/2/04 30% 2020
On 3/22/10 HB 1001 increased the RPS standard to 30% by 2020. Requires large
investor-owned utilities serving 40,000 or more customers to generate or purchase
12% of their retail electric sales from eligible renewable energy resources (solar,
wind, geothermal, biomass, and small hydroelectric) by 2010, increasing to 20% by
2015, and 30% by 2020. 3% of these amounts must come from distributable solar-
electric technologies. RECs may be used to satisfy standard
New Mexico
3/5/07 20% 2020
20% of an electric utility’s power must come from renewable sources. Resources
include solar, wind, hydropower, geothermal, fuel cells from renewable fuels, and
qualifying biomass. Performance-based financial or other incentives are used to
encourage utilities to exceed annual standards.
Connecticut
7/1/98 27% 2020
On 6/4/07 HB 7432 increased the RPS standard to 20% renewables from "Class I"
(solar, wind, sustainable biomass, ocean-generated, landfill gas, 5MW hydro), 3%
from "Class I" or "Class II" (trash-to-energy, hydro facilities, and other biomass),
and 4% from "Class III" (distributed heat, conservation, waste recovery programs).
New York
9/22/04 29% 2015
On 1/8/10 NY SPC increased RPS to 29% of renewables by 2015. 20.7% of target
from existing facilities and 8.3% from new sources categorized into two-tiers. "Main
Tier", roughly 93% of incremental renewables generation (biogas, biomass, liquid
biofuel, fuel cells, hydroelectric, solar, ocean or tidal power, and wind). "Customer-
Sited Tier" 7% of incremental renewables generation (fuel cells, solar, and wind
resources). An additional 1% to come through voluntary power sales.
District of
Columbia
1/19/05
11% 2022
Two-tiered system: "Tier 1" includes solar, wind, biomass, landfill gas, wastewater-
treatment gas, geothermal, ocean-generating, and fuel cells from renewable fuels.
"Tier 2" includes hydropower and municipal solid waste. Additional 0.386% of the
district’s renewable energy to come from solar energy by 2022. On 7/2/10 DC Law
18-0223 amended the RPS so that municipal solid waste incineration may not be
used to meet more than 20% of a Tier 2 requirement. Beginning 2013 municipal
solid waste will no longer be eligible to generate Tier 2 RECs.
North Carolina
8/20/07 12.5% 2021
By 2021, 12.5% of retail sales must come from renewable energy or energy
efficiency for investor-owned utilities. 10% by 2018 for electric cooperatives and
municipal utilities.
Delaware
7/21/05 25% 2025
18% from renewable resources by 2019 (wind, ocean-generated, fuel cells from
renewable fuels, 30MW hydroelectric facilities, sustainable biomass, anaerobic
digestion, and landfill gas). 3.5% of state electricity supply from solar PV by 2025.
North Dakota*
3/21/07 10% 2015 Voluntary RPS passed by legislature of 10% retail electricity sold to come from
renewables by 2015.
Florida
An Executive Order from July 13, 2007 directed the state commission to draft RPS
rules. On Jan. 30, 2009 the Florida Public Service Commission proposed a RPS to
the state Legislature requiring 20% generation from renewable resources by 2020.
Other target dates: 7% by 2013, 12% by 2016 and 18% by 2019. The Florida
Legislature did not act on or ratify the legislation in 2009 or 2010.
Ohio
5/1/08 25% 2025
12.5% electricity sold in the state to come from renewables (wind, solar,
hydropower, geothermal, or biomass), half of which must be generated in Ohio.
Other 12.5% may come from alternative energy resources (nuclear power plants,
fuel cells, energy-efficiency, and clean carbon capture technology). Utilities may
buy, sell, and trade renewable energy credits to comply. 22.5% by 2025 to come
from energy efficiency savings. Electric utilities must reduce peak energy demand
1% in 2009, and an additional 0.75% each year through 2018.
Hawaii
6/2/04 25% 2020
10% of net electricity sales to come from renewable sources by 2010, 15% by 2015
(wind, solar, ocean thermal, wave, and biomass). On June 25, 2009, RPS was
increased to 25% by 2020 and 40% by 2030. 30% by 2030 to come from energy
efficiency savings.
Oregon
6/6/07 25% 2025
25% of utility electric load from new renewable sources by 2025. Resources include
wind, solar, wave, geothermal, biomass, new hydro or upgrades to existing hydro
facilities. On 6/25/09 HB 3039 required 20 MW by 2020 to come from solar
photovoltaic.
Iowa
10/21/83
105
MW
Not an official RPS, but 1983 Alternative Energy Production state law mandates two
investor-owned utilities (Mid-American and Interstate Power/Light) to own or
contract for 105 MW of renewable power (photovoltaics, landfill gas, wind, biomass,
hydro, municipal solid waste, and anaerobic digestion). Voluntary goal of 1,000 MW
of wind capacity by 2010.
Pennsylvania
12/16/04 18% 2020
Two-tiered resources to meet RPS: 8% from Tier 1 (wind, solar, coalmine methane,
small hydropower, geothermal, and biomass), 10% from Tier 2 (waste coal, demand
side management, large hydropower, municipal solid waste, and IGCC), and 0.5%
must be solar-provided generation (part of Tier 1) by 2020.
Illinois
8/28/07 25% 2025
10% by 2015 and 25% by 2025. 75% of the electricity used to meet the RPS must
come from wind power generation, 6% from new solar photovoltaic by 6/1/2015.
Eligible renewables include solar, biomass, and existing hydropower. Utilities to
implement energy efficiency standard to reduce electric usage by 2% of demand by
2015.
Rhode Island
6/29/04 16% 2019
3% of retail electricity sales must come from renewable energy by 2006, increasing
1% a year through 2020. Existing renewables count for only 2% of RPS, the rest
must be from new renewable production. Resources include direct solar radiation,
wind, ocean-generated, the heat of the earth, small hydroelectric facilities, eligible
biomass, and fuel cells using renewable fuels. The PUC will review/revise the
schedule after 2013.
Kansas
5/22/09 20% 2020
Generate or purchase renewable energy of 10% by 2011, 15% by 2016 and 20% by
2020 and beyond. Generated energy counts as 1.1 MW for each MW. Eligible
sources include wind, solar thermal and photovoltaic, dedicated agricultural or plant
waste, untreated wood, fuel cells, existing hydropower and new hydropower of 10
MW or less.
South Dakota*
2/21/08 10% 2015 Voluntary RPS of 10% retail electricity sold to come from renewables by 2015.
Maine
9/28/99
10%
new 2017
Original standard of 30% by the year 2000. RPS was increased in June 2006 an
additional 10% by 2017 for new renewable sources (fuel cells, tidal power, solar,
wind, geothermal, hydro, biomass, or municipal solid waste recycling) placed into
service after 9/1/05.
Texas
6/18/1999
5,880
MW 2015
On 8/1/05 SB 20 increased RPS to 5,880 MW of new renewable generation to be
built in state (about 5% of the state's electricity demand) by 2015. Goal of 10,000
MW in renewable generation capacity by 2025. 500 MW by 2025 from non-wind
resources.
Maryland
5/26/04 20% 2022
On 4/24/08 the RPS was accelerated to 20% of state’s electricity supply must come
from renewable sources by 2022. At least 2% must come from solar sources and
7.5% from other renewable sources (wind, biomass, anaerobic digestion, landfill
gas, geothermal, ocean-generated, fuel cells from renewable fuels, and small
hydro) by 2022.
Utah*
3/18/08 20% 2025 Voluntary RPS goal of 20% of adjusted retail sales by 2025. Utilities to pursue cost-
effective renewable energy.
Massachusetts
7/2/08 15% 2020
New law updates previous RPS of 4% in 2009 to 15% new renewable electricity
generation by 2020 with 1% increase each subsequent year, with no set expiration.
Renewables include solar, wind, ocean, fuel cells from renewable fuels, landfill gas,
biomass, marine, and geothermal.
Vermont*
6/14/05 10% 2013
Voluntary goal of 10% of 2005 total electric sales to be achieved by 2012, else RPS
will become mandatory in 2013. Renewable resources include wind, solar, large
hydropower, landfill methane gas, anaerobic digesters, and sewage-treatment
facilities excluding municipal solid waste. Vermont utilities can build generation out
of state to comply with RPS. On 3/20/08, new renewable goal of 25% by 2025
emphasizing use of Vermont's farms and forests. On 6/4/10 HB 781 required the
PSB to considering changing state's RPS goals to a full-fledged RPS standard. PSB
report due 10/1/11.
Michigan
10/6/08 10% 2015
Qualifying sources include wind, solar, hydropower, landfill gas, waste combustion
and cogeneration. Advanced fossil fuel technologies and efficiency measures may
be used to cover some of a utility's obligation.
Virginia*
4/11/07 15% 2025
Voluntary RPS goal (updated 4/2/10) of 15% of 2007 base year utility electricity
sales (excluding average nuclear power supply) by 2025. Resources include solar,
wind, geothermal, hydropower, wave, tidal, and biomass energy. Wind and solar
receive a double credit toward RPS goals. Offshore wind receive a triple credit.
Investor-owned utilities are incentivized with increased rate of return to procure a
percentage of the power sold in VA from eligible renewable energy sources.
Minnesota
2/22/07 25% 2025
Xcel Energy (generates about half of the state’s electricity) required to produce 30%
from renewable sources by 2020. "Eligible Renewable Energy Technologies"
include solar, wind, small (<100MW) hydroelectric, hydrogen from renewable
resources, and biomass.
Washington
11/7/06 15% 2020
All utilities in WA serving more than 25,000 people must produce 15% of their
energy using renewable sources by 2020. Resources include water, wind, solar,
geothermal, landfill gas, wave, ocean, tidal power, gas from sewage treatment
facilities, biodiesel fuel not from deforested land and biomass.
Missouri
11/4/08 15% 2021
Voters passed proposition C for state-wide RPS repealing current voluntary
standard. Investor-owned utilities qualify with their own generation or renewable
energy credits (2% from solar sources). 2% by 2011; 5% by 2014; 10% by 2018.
West Virginia
6/17/09 25% 2025
10% by 2015 and 15% by 2020 from alternative or renewable energy sources.
Eligible alternatives include advanced coal technology (e.g., carbon capture and
storage, ultra/supercritical and pressurized fluidized bed technologies), coal bed
methane, natural gas, coal gasification or liquefaction facility-produced fuel,
synthetic gas, IGCC, waste coal, tire-derived fuel, pumped storage hydroelectric,
and recycled energy. Eligible renewables are solar, wind, hydropower, geothermal,
biomass, biofuels, and fuel cells.
Montana
4/28/05 15% 2015
Utilities can meet the standard by entering into long-term purchase contracts for
electricity bundled with renewable energy credits. The law includes cost caps that
limit the additional cost utilities must pay for renewable energy. Resources include
wind, solar, geothermal, existing hydro, landfill or farm-based methane gas,
wastewater-treatment gas, nontoxic biomass, and fuel cells from renewable fuels.
Wisconsin
10/27/99 10% 2015
On 3/17/06 RPS was increased to 10% by 2015. Qualifying renewables include tidal
and wave action, fuel cells using renewable fuels, solar, wind, biomass, geothermal
technology, and hydropower less than 60 MW. Renewable energy generated
outside of Wisconsin is eligible.
Nevada
3/15/07 25% 2025
SB 395 on 6/8/09 increased RPS to: 20% by 2015, at least 5% must be generated
from solar energy. Utilities can also earn credit for up to 25% of the RPS through
energy efficiency measures. Resources include biomass, fuel cells, geothermal,
solar, hydro, and wind. On June 8, 2009 RPS was updated to 25% by 2025 (6%
from solar by 2016).
* Denotes states that have set voluntary goals for adopting renewable energy standards instead of mandatory targets.
Sources: http://www.eere.energy.gov/states/maps/renewable_portfolio_states.cfm
http://www.pewclimate.org/what_s_being_done/in_the_states/rps.cfm
Company data, KeyBanc Capital Markets Inc.
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 14 of 53
August 2011
STOCK PERFORMANCE DIVERGENCE BASED ON COMMODITY EXPOSURE
The strong (if not volatile) commodity cycle had for years been favorable for companies that have exposure to natural gas and/or coal,
as they have typically outperformed the rest of the group, as depicted in Chart 5. In 2009 and 2010, the commodity subgroup fared the
worst in the economic downturn, as natural gas, coal and power prices have fallen with a sluggish economic outlook. Despite a brief
period of outperformance in spring 2009, any investor enthusiasm in the commodity subgroup has remained somewhat muted.
However, the unregulated generators have recently started to attract interest as investors started to weigh the impact of EPA
regulations on the existing coal fleet. This enthusiasm has waned somewhat as economic concerns have intensified.

We believe that the rapid and pronounced price declines were driven by several factors: the collapse of major banks likely drove forced
liquidation of long commodity positions; reduced demand in light of a slowing global economy (especially China, which had been a
major importer); volatility arising from marketplace assumptions on the effects of various government stimulus programs around the
world; opening of new unconventional natural gas plays (with improving production technology) expanding gas supply; and investor
realization that any economic recovery may be longer-dated, and that demand is down due, in part, to a shift in changing consumer
behaviors. The recent (July and August) market turmoil has driven outperformance by names offering liquidity and yield, particularly
relative to treasuries. Smaller names and unregulated companies have lagged these defensive plays in this period.

Chart 5. Price Performance of Different Utility Subgroups
(December 31, 2006 – August 23, 2011)

Source: FactSet

The 2011 year-to-date performance for commodity-focused nuclear names took a severe drop in mid-March during the Japanese
nuclear crisis as risk-averse investors avoided these generators, while the broader market index outperformance earlier in the year lost
its ground against integrated utilities as investors took profits and sought safety in our sector while assessing the strength of global
economic recovery (see Chart 6).

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 15 of 53
August 2011
Chart 6. Year-to-Date S&P 500 vs. KBCM Electric Utility Segment Performance
(December 31, 2010 – August 23, 2011)

-12%
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
De
c
-
1
0
Ja
n
-
1
1
Fe
b
-
1
1
Ma
r
-
1
1
Ap
r
-
1
1
Ma
y
-
1
1
Ju
n
-
1
1
Ju
l
-
1
1
Au
g
-
1
1
Date
Re
t
u
r
n
T&D Only
Small Vertical
Large Vertical
Commodity
S&P 500

Source: FactSet

JAPAN NUCLEAR CRISIS HIGHLIGHTS RISKS TO NUCLEAR POWER INDUSTRY
The sharp decline in mid-March 2011 for all equity segments, including the broader market, arose from concerns about the Fukushima
nuclear power complex in Japan that was severely damaged and leaking radiation due to the combination of an earthquake and
tsunami. With 20% of U.S. power derived from nuclear energy, we do not envision a knee-jerk reaction in the United States to impact
nuclear power. However, we do believe U.S. nuclear energy is likely to be impacted by increased scrutiny, inspections and
considerations of specific reactor designs, as well as the sufficiency of backup systems in the event of station blackout conditions.

The situation is also likely to fuel increased opposition to nuclear power, as did the Three Mile Island and Chernobyl incidents. Three
Mile Island is considered to have been a major factor in the end of U.S. nuclear construction already hindered by construction delays
and cost overruns. Existing plants on the public perception bubble (Vermont Yankee, for example) and others up for licensing renewals
could face further public scrutiny.

New nuclear construction, which has already been delayed by the recession, is likely to see higher opposition. Proponents of nuclear
will argue that modern plants are simpler in design and designed to shut themselves down in emergencies. Opponents will cite another
occurrence of an event that design redundancies would supposedly prevent from happening. We expect the construction of Southern
Company’s Vogtle 3 and 4 plants to continue, although with potential greater design review. The Japanese accident is likely to further
drive incremental generation capacity decision making to favor natural gas, which could impact diversity and drive power pricing
volatility. Public and political perceptions around nuclear energy will contribute to policy discussions.

An August 23 earthquake on the U.S. East Coast drove a short-lived negative investor reaction as companies with nuclear exposure
saw a brief sell-off. However, as news started to flow that the plants suffered no damage and all-systems reacted as designed to,
market concerns were alleviated. Nuclear proponents touted the incident as an example of the safety of the United States nuclear fleet.

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 16 of 53
August 2011
NEW GENERATION / TRANSMISSION BUILD TO MEET LOAD GROWTH
On the supply side, the industry has worked off much of the capacity glut that resulted from a late 1990s building frenzy, which was
fueled by cheap natural gas, robust economic growth and optimistic investors. Regionally, several parts of the country have recognized
the fact that long construction lead times (particularly for baseload generation) suggest a sense of urgency around planning for new
capacity. The recent economic slowdown, however, has temporarily slowed demand growth while new capacity projects were already
underway, thus improving load margins in the intermediate forecast term (see Chart 7).

Chart 7. Historical and Forecasted U.S. Electric Supply and Demand
(Summer)

0
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(
M
W
)
0%
5%
10%
15%
20%
25%
30%
Ma
r
g
i
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Demand
Supply
Margin
Source: North American Electric Reliability Corp, 2010 Historic Capacity and Demand Report

COST ESCALATION IN NEW GENERATION BUILD
While recent prices may have come off of their earlier highs due to the global economic crisis slowing construction demand, we believe
the long-term trend of rising construction materials costs could resume as the global economy rebounds. The cost of building new
generation remains a moving target, as worldwide demand for construction materials commodities (steel, concrete and copper), labor
and components (turbines and boilers) would remain fundamentally strong, driven by a rebound in the U.S. and Chinese economies
and required compliance with future U.S. environmental regulations. We believe this presents challenges to both unregulated and
regulated investment in new generation plants. In particular, on the regulated side, there exists a chicken-and-egg problem in that
securing pricing without a regulatory buy-in is as difficult as receiving regulatory pre-approval without firm pricing. For example, in order
to secure the project’s expected final approval, Southern Company subsidiary Mississippi Power agreed to a cost cap on its 582MW
Kemper County IGCC plant at $2.88 billion to allow the Commission to protect and assure customers against uncontrolled cost
increases from its original $2.7 billion estimate. In addition to this regulatory quagmire is uncertainty around the cost to achieve yet to
be determined environmental controls to mitigate carbon output.

Chart 8 illustrates the upward pressure on construction commodities, with the global economic slowdown affecting prices in the near
term and some recent indications and forecasts of price stabilization and increases. As an example of longer-dated cost escalation on
new generation build, Progress Energy had recently estimated the cost of building two new nuclear plants, with necessary transmission,
at $17 billion, more than twice initial estimates.

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 17 of 53
August 2011
Chart 8. Construction Materials Indexed Pricing

80
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Date
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l
a
t
i
v
e

P
r
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c
e

%
Steel Rebar Concrete Copper
Source: Bureau of Labor Statistics and Steel Business Briefing (as of August 24, 2011).

The long-term trend of rising costs increasingly necessitates the need for rate-making mechanisms, such as Construction Work In
Progress (CWIP), to allow utilities to undertake construction without significantly weakening their balance sheet, cash flow and credit
metrics. Additional cost pressures on ratepayers pose the risk of regulators authorizing lower ROEs in future rate proceedings to offer
some rate relief.

FIFTEEN PERCENT DIVIDEND TAX RATE EXTENSION
A reduced 15% tax rate on corporate dividends (same as the long-term capital gains tax rate) provided a positive catalyst for continued
investment in higher-yielding stocks when it was introduced in 2003 under former President Bush. As expiration of these tax rates
loomed toward the end of 2010, President Obama signed into law the Tax Relief Unemployment Insurance Reauthorization and Job
Creation Act of 2010 on December 17 (after compromising with congressional Republican leaders), which extended the lower dividend
and capital gains tax rates for two years through 2012.

We believe that 1.0-1.5x P/E multiple points of the group’s valuation expansion over the past years were attributable to these lower
taxes and extension prevented a negative catalyst for the utility group. Currently, our coverage universe averages a 4.4% dividend
yield vs. 2.2% for the S&P 500 index. We believe our sector will remain particularly sensitive to news on dividend taxes as our sector is
likely to again experience similar circumstances of political debate over lower dividend tax rate expiration in 2012.
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 18 of 53
August 2011

M&A ACTIVITY ON THE RISE
We expect that many utility executives are looking at the potential synergies of a strategic and well-executed merger with great interest,
particularly with the recent pick up in M&A activity (see Table 6). Companies with substantial unregulated operations would most likely
be able to realize the greatest amount of synergies, as these savings are generally outside the reach of regulators. With balance
sheets generally repaired (and the potential for all-stock deals to offer further improvement), we consider additional consolidation to be
likely in the long term. The outlook for an extended period of low power prices may accelerate M&A to achieve cost synergies. We
would expect larger players to look for opportunities to gain scale to endure weakened markets and capital needs through a greater
unregulated presence or through the addition more stable regulated operations. On the regulated side, we believe smaller, single-state
utilities make attractive targets.

POSSIBLE ACQUIREES
Cleco Corporation (CNL-NYSE)
As a small, single-state regulated utility in Louisiana with a service territory next to Entergy, we believe Cleco Corporation is a
potential acquisition target. We expect forecast free cash generation could be attractive to acquirers.

NiSource, Inc. (NI-NYSE)
We believe NiSource, Inc. is perceived as an acquisition target. The announced acquisition and bidding war for Southern Union
Company (SUG-NYSE) has served to fuel this view. However, we believe a presence in several jurisdictions would present
considerable risk of achieving reasonable approvals across the board. Further, we believe current management will continue down
the path of getting back on course alone.

TECO Energy, Inc. (TE-NYSE)
As a small, single-state regulated utility in Florida, we believe TECO Energy, Inc. is a potential acquisition target and an attractive
candidate for a contiguous merger. TECO’s coal assets could make it an intriguing name as well.

POSSIBLE ACQUIRERS
Dominion Resources, Inc. (D-NYSE)
Dominion was rumored to have been interested in acquiring Progress Energy away from Duke Energy. Since then, the Company
has stated that it continues to focus on its organic growth plan and in achieving a 5-6% long-term earnings growth target. We
believe that the Company would consider any opportunities that were accretive to earnings and shareholder value.

Entergy Corporation (ETR-NYSE)
After having failed to spin-off its unregulated nuclear wholesale business in recent years, Entergy Corporation may be looking to
return to growth through acquisition. We believe regulatory goodwill and state political support would be keys to successfully
executing any transaction involving Entergy.

Southern Company (SO-NYSE)
With historically strong currency, we expect Southern Company is looking at potential acquisitions. Given the relative ease of
asset purchases compared to whole companies, we suspect Southern may be interested in tucking in merchant assets at its
Southern Power subsidiary. Liquidity pressures at merchant players could be alleviated by divestitures. Unlike the last market
downturn, we do not envision private equity putting a floor on generation valuations. Alternatively, if Southern were to pursue a
whole company, we believe management may seek to green up the Company’s generation portfolio, which is currently heavily
coal-burning.

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 19 of 53
August 2011
RECENT M&A ACTIVITY UPDATE
Gaz Metro L.P. and Central Vermont Public Service Corporation
On July 12, 2011, Central Vermont Public Service Corporation (CV-NYSE) announced it had accepted a superior unsolicited offer
to be acquired by Canadian firm Gaz Metro Limited Partnership at $35.25 per common share. Gaz Metro also owns Central
Vermont’s neighboring utility Green Mountain Power. This deal terminated a previous agreement Central Vermont had reached
with Fortis Inc. on May 30, 2011 at $35.10 per share. Central Vermont indicated that superior benefits drove the decision to accept
the unsolicited offer, given $144 million in customer benefits over 10 years, a donation to a Vermont trust of a share of the
transmission company VELCO, and full dividend payments to shareholders until the deal closes. Of note is the breakup fee of up
to $19.5 million, payable to Fortis, which is essentially borne by Gaz Metro as it will be funded by Central Vermont’s balance sheet
that Gaz Metro is acquiring. The sale is expected to be completed in 6-12 months and subject to regulatory approval by the
Vermont Public Service Board and U.S. Federal Energy Regulatory Commission (FERC).

Exelon Corporation and Constellation Energy Group, Inc.
On April 27, 2011, Exelon Corporation (EXC-NYSE) announced its plans to merge with Constellation Energy Group, Inc. (CEG-
NYSE) in a stock-for-stock deal valued at $10.6 billion enterprise value. The combined company will be the country’s largest
competitive power generator with more than 34 GW of power generating capacity, own the nation’s largest nuclear fleet of nearly
19,000 MW and serve 6.6 million customers through its electric and gas distribution utilities in Maryland, Illinois and Pennsylvania.

Constellation shareholders will receive 0.93 shares of Exelon common stock (April 27 Execelon closing price of $41.49 implies
Constellation shareholder value of $38.59 per share, or $7.9 billion equity value). The companies are targeting a close in early
2012, with regulatory approvals required primarily from U.S. FERC, Nuclear Regulatory Commission (NRC), Maryland Public
Service Commission, New York Public Service Commission and the Public Utility Commission of Texas.

AES Corporation and DPL Inc.
On April 20, 2011, DPL Inc. (DPL-NYSE) announced its plans to be acquired by The AES Corporation (AES-NYSE) in a
transaction with an enterprise value of $4.7 billion. DPL shareholders will receive $30.00 cash per share totaling approximately
$3.5 billion cash equity value. The companies are targeting a close in the next six to nine months, with regulatory approvals
required from Federal Energy Regulatory Commission (FERC) and the Public Utilities Commission of Ohio (PUCO). We had
always highlighted DPL as an attractive take-out candidate, given its smaller market capitalization and single-state jurisdiction.

Duke Energy Corporation and Progress Energy, Inc.
On January 10, 2011, Duke Energy Corporation (DUK-NYSE) announced its plans to merge with Progress Energy, Inc. (PGN-
NYSE) in a stock-for-stock transaction valued at $25.7 billion. The combined company will be the country’s largest utility, having
about 57 GW of domestic generating capacity serving approximately 7.1 million electric customers in the six states of North
Carolina, South Carolina, Florida, Indiana, Kentucky and Ohio.

Progress Energy shareholders will receive 2.6125 shares of common stock in Duke Energy (January 7 Progress Energy closing
price of $46.48 implies $13.7 billion equity value) and Duke Energy will assume about $12.2 billion of Progress Energy net debt.
The companies are targeting a close by the end of 2011, with regulatory approvals required from Federal Energy Regulatory
Commission (FERC), Nuclear Regulatory Commission (NRC), North Carolina Utilities Commission (NCUC) and South Carolina
Public Service Commission (SCPSC).

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 20 of 53
August 2011

Table 6. Recent Utility M&A Activity

Date
Announced Acquirer Acquiree Consideration
Offer Price
per Share
Implied Value at
Announcement1
Premium at
Announcement2
7/12/11 Gaz Metro L.P Central Vermont Public Service Corp. 100% Cash $35.25 $704.1 million 44.9%4
4/28/11 Exelon Corporation Constellation Energy Group, Inc. 100% Stock 0.930 shares $10.6 billion 12.5%
4/20/11 AES Corporation DPL Inc. 100% Cash $30.00 $4.7 billion 8.7%
3/2/11 PPL Corporation Central Networks (from E.ON UK plc) 100% Cash N/A $6.40 billion N/A – Subsidiary
1/10/11 Duke Energy Corporation Progress Energy, Inc. 100% Stock 2.6125 shares $25.7 billion 3.9%; [6.4%] 3
12/7/10 AGL Resources Inc. Nicor Inc. 40% Cash and
60% Stock
$21.20 and
0.8382 shares $3.1 billion 13.3%
10/18/10 Northeast Utilities NSTAR 100% Stock 1.312 shares $7.56 billion 1.9%
8/13/10 Blackstone Group, L.P. Dynegy Inc. 100% Cash
(Failed)
$4.50 at annc.
($5.00 final) $4.6 billion 61.8%
4/28/10 PPL Corporation E.ON U.S. (Louisville Gas & Electric
and Kentucky Utilities) 100% Cash N/A $7.63 billion N/A - Private
4/21/10 Calpine Corporation Conectiv Energy Holding Co. 100% Cash N/A $1.65 billion N/A - Subsidiary
4/11/10 Mirant Corporation RRI Energy, Inc. 100% Stock 0.353 shares $1.63 billion 4.4%
2/11/10 FirstEnergy Corporation Allegheny Energy, Inc. 100% Stock 0.667 shares $8.5 billion 31.6%
10/20/08 Exelon Corporation NRG Energy, Inc. 100% Stock
(Failed) 0.485 shares $6.15 billion 36.7%
10/26/07 Macquarie Consortium Puget Energy, Inc. 100% Cash $30.00 $7.4 billion 25.3%
6/25/07 Iberdrola SA Energy East Corporation 100% Cash $28.50 $8.50 billion 27.4%
2/26/07 KKR TXU Corp. 100% Cash $69.25 $44.16 billion 15.4%
2/7/07 Great Plains Energy Inc. Aquila Inc. 55% Cash and
45% Stock
$1.80 and
0.0856 shares $2.8 billion -2.7%
7/8/06 MDU Resources Group Cascade Natural Gas Corp. 100% Cash $26.50 $471.2 million 23.5%
7/5/06 Macquarie Consortium Duquesne Light Holdings Inc. 100% Cash $20.00 $2.59 billion 21.7%
4/25/06 Babcock & Brown NorthWestern Corporation 100% Cash
(Failed) $37.00 $2.23 billion 15.3%
12/19/05 FPL Group, Inc. Constellation Energy Group, Inc. 100% Stock
(Failed) $62.02 $14.42 billion 0.65%; [15.0%] 3
Notes:
Deals currently pending in italics
1) Deal transaction value (includes debt assumed)
2) 1-day closing stock price premium
3) [20-day average closing stock price premium]
4) Prior to previous agreement announced on May 30, 2011
Source: Company data, KeyBanc Capital Markets Inc. estimates
KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

Page 21 of 53
August 2011

SHORT INTEREST OVERVIEW
Toward the end of 2010, sector concerns of a longer-dated U.S. economic recovery (dampening electric demand), weak initial outlooks
by some companies heading a new year, challenged power prices for merchant generators and questions around dividend security all
contributed to the group trading at a discount to the S&P 500. We believe that many of these topics of concern were addressed by
company managements during the 1Q and 2Q earnings seasons, leading to renewed confidence in the stability of our industry and
subsequent sector outperformance (see Chart 9) as a defensive play amid broader market concern of a slower global economic
recovery. A pick-up in M&A activity, double-dip U.S. recession fears and European sovereign debt issues appear to have dampened
any enthusiasm for a quicker or stronger than expected economic recovery, leading to sharp broader market declines in July 2011.

Chart 9. 2012 P/E Comparison of KBCM Utility Coverage vs. S&P 500
(December 31, 2010 – August 22, 2011)

Source: FactSet

Historically, underperformance in our sector has provided opportunities for investors to cover their short positions. Toward the end of
2009, short interest crept back higher, primarily due to large-cap names Duke, Dominion and Exelon, as investors may have started
realizing that any robust economic recovery for electric utilities may take longer than expected. Modest short interest declines in early
2010 may have been driven by early hopes of economic recovery. During the past summer, short interest picked up again within the
group, likely related to a less optimistic view around merchant exposure, as a sluggish economy and sustained weakness in natural gas
pricing appear to have dampened expectations around a recovery in power pricing. Arbitrage activity around M&A appeared to have
also contributed to higher short interest (FirstEnergy and PPL) in 2010. Heading into 2011, sector underperformance again allowed
investors to cover their short position as evidenced by the declines through March. Short interest has steadily increased through 2Q11,
likely from increased shares and positioning due to M&A related activity, as well as our sector having outperformed the broader market.
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Page 22 of 53
August 2011
Table 7. Monthly Short Interest

(days) (shares in millions)
Shares Current 2011 2010 2009
Company Ticker Out Short Ratio Jul Jun May Apr Mar Feb Jan Dec Nov Oct Sep Aug Jul Jun May Apr Mar Feb Jan Dec
Ameren Corp. AEE 241.7 2.4 4.2 5.1 5.5 6.0 5.5 7.4 9.1 7.7 7.8 6.2 7.0 9.3 6.9 6.1 6.4 6.6 5.7 4.5 3.9 4.5
American Electric Power Co. AEP 482.3 1.0 4.3 5.5 7.3 5.0 3.8 4.8 4.8 4.0 5.9 7.6 8.5 8.5 11.7 7.2 5.3 4.6 5.1 4.7 9.0 11.4
Avista Corp. AVA 58.0 8.2 2.1 1.9 1.6 1.5 1.5 1.4 1.3 1.5 1.6 1.5 1.9 2.5 2.6 1.9 2.1 2.1 2.0 2.1 2.4 2.5
CMS Energy Corp. CMS 253.4 6.6 16.6 13.0 12.5 17.1 10.4 13.2 11.3 13.9 21.1 25.3 37.6 42.3 41.9 38.5 35.9 37.5 33.3 32.9 32.6 31.3
Central Vermont Public Svc. Corp. CV 13.4 4.8 0.3 0.4 0.4 0.4 0.4 0.3 0.3 0.3 0.3 0.3 0.4 0.5 0.5 0.5 0.5 0.5 0.4 0.4 0.3 0.3
Cleco Corp. CNL 61.1 12.6 3.6 3.7 4.0 4.4 2.8 2.3 2.4 3.4 3.9 3.5 3.9 4.0 3.7 3.2 3.6 2.0 2.3 2.8 2.4 2.5
Consolidated Edison, Inc ED 292.9 10.3 14.1 13.1 11.8 9.5 7.3 7.7 7.2 7.0 5.6 7.4 11.1 11.2 10.7 10.9 8.2 6.6 6.5 7.4 9.4 9.3
DPL Inc. DPL 117.7 4.2 2.4 2.5 3.2 5.0 6.5 6.3 6.6 6.0 5.2 4.7 5.1 4.1 3.2 3.9 3.3 2.6 2.9 2.6 3.6 3.4
DTE Energy Co. DTE 169.3 2.1 1.8 2.3 3.4 2.7 2.2 1.5 1.6 1.8 1.9 2.7 3.0 4.1 7.2 8.1 6.8 6.4 5.6 6.5 7.2 7.9
Dominion Resources, Inc. D 569.2 5.5 12.5 13.7 13.3 11.4 10.6 10.2 8.1 8.1 10.2 11.9 15.7 16.1 12.1 13.0 11.4 13.9 15.0 12.9 11.3 15.5
Duke Energy Corp. DUK 1,331.8 4.0 44.0 38.4 31.8 29.9 23.8 23.0 26.2 21.9 21.2 18.4 21.4 21.1 21.7 19.3 23.2 18.1 22.5 22.4 25.0 34.2
Entergy Corp. ETR 176.8 1.4 2.9 3.5 3.7 3.8 2.6 2.8 2.5 1.8 2.2 2.9 3.4 3.6 2.8 2.4 3.3 2.6 3.2 2.5 2.3 2.5
Exelon Corp. EXC 662.7 3.6 19.7 19.5 16.9 13.1 12.6 14.6 14.3 15.0 13.8 20.4 18.5 17.6 15.5 15.1 13.8 14.7 12.4 10.5 11.1 11.0
FirstEnergy Corp FE 418.2 0.9 3.1 4.4 4.7 7.5 5.8 30.1 30.4 30.4 28.8 27.2 25.8 23.9 19.3 17.4 14.6 11.0 8.6 4.8 5.2 5.8
Great Plains Energy, Inc. GXP 136.0 3.9 5.2 5.4 6.2 6.2 5.5 4.7 5.2 6.0 7.7 7.8 7.9 7.6 6.8 5.0 5.3 5.0 5.7 5.6 5.5 6.8
IDACORP, Inc. IDA 49.7 8.9 1.6 1.9 1.7 1.8 1.4 1.3 1.2 1.2 1.2 1.2 1.7 2.1 2.1 1.5 1.8 1.9 1.9 2.2 1.9 1.7
MDU Resources Group, Inc. MDU 188.8 3.3 1.8 2.3 2.7 2.3 2.1 1.1 1.5 1.2 1.8 1.2 1.0 0.7 1.2 0.9 0.5 0.6 0.6 1.0 1.1 1.3
NextEra Energy, Inc. NEE 422.3 3.2 5.1 4.9 4.4 5.0 3.9 3.9 4.3 3.3 4.3 5.2 6.4 5.7 5.1 5.1 6.8 5.8 4.4 4.0 3.9 5.7
NiSource, Inc. NI 280.6 2.6 8.1 6.1 8.0 5.6 5.2 6.2 5.9 5.1 4.8 6.1 6.9 11.7 12.3 9.4 8.0 8.1 10.6 7.6 9.6 7.0
NorthWestern Corp. NWE 36.3 7.3 1.7 1.5 1.4 1.1 1.0 0.9 0.9 0.9 1.2 1.3 1.7 1.4 1.5 1.3 1.5 2.4 1.5 1.9 1.6 2.1
PPL Corp. PPL 577.7 3.8 14.1 12.2 13.4 14.5 7.9 7.1 7.1 5.4 8.0 7.4 8.1 8.2 7.3 7.3 5.7 2.3 2.5 1.7 2.1 2.6
Pepco Holdings, Inc. POM 226.4 8.4 11.5 12.0 14.1 10.4 13.2 11.7 11.6 10.4 10.5 14.0 14.2 14.1 13.5 12.6 12.3 9.5 10.2 9.9 10.0 8.6
Pinnacle West Capital Corp. PNW 109.1 2.5 1.9 1.7 1.2 1.3 1.1 1.2 1.5 1.6 1.5 2.7 3.9 3.3 4.2 2.9 2.4 1.9 2.6 2.4 2.7 2.7
Progress Energy, Inc. PGN 294.6 3.0 3.5 3.0 3.1 3.2 3.3 3.4 4.4 4.3 4.3 5.0 6.0 5.7 5.4 4.1 4.4 3.8 7.0 5.6 4.5 5.3
Southern Company SO 857.7 2.4 10.2 8.9 7.6 6.7 6.8 6.8 6.3 9.6 11.9 10.5 10.5 12.2 12.1 9.5 12.8 15.7 15.6 14.8 11.3 9.1
TECO Energy, Inc. TE 215.7 2.5 4.4 4.9 6.7 4.1 2.2 1.9 3.2 4.9 4.6 5.5 5.5 6.2 3.7 3.3 3.7 2.7 3.5 4.2 5.3 8.6
Wisconsin Energy Corp. WEC 233.7 4.7 7.0 5.5 5.0 5.5 5.7 5.4 6.9 6.2 5.3 4.6 6.9 6.7 6.9 5.2 4.0 5.3 6.7 7.7 6.3 5.3
Xcel Energy Inc. XEL 484.6 2.1 4.7 5.1 5.4 6.4 4.7 4.4 3.4 5.4 7.9 6.5 6.5 7.7 9.8 8.6 8.6 8.5 10.3 9.7 9.7 8.1
Total 8,961.6 212.2 202.4 200.9 191.3 159.7 185.6 189.6 188.5 204.6 219.0 250.6 261.9 251.3 224.2 216.3 202.8 208.6 195.6 201.4 217.0

Note: Historical share counts adjusted for WEC 2:1 stock split on March 1, 2011
Source: Bloomberg, August 23, 2011

KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC
Equity Research

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August 2011

PINNACLE WEST CAPITAL CORPORATION (PNW-NYSE) — LOWERING 2011 ESTIMATE DUE
TO WEATHER — reprinted from 08/10/2011

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August 2011

GREAT PLAINS ENERGY INCORPORATED (GXP-NYSE) — LOWERING ESTIMATES; ANALYST
MEETING TAKEAWAYS — reprinted from 08/10/2011

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August 2011

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August 2011

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GREAT PLAINS ENERGY INCORPORATED (GXP-NYSE) — WARMING UP TO GXP HEADING
INTO ANALYST DAY, INTRODUCING 2013E — reprinted from 08/04/2011

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WISCONSIN ENERGY CORPORATION (WEC-NYSE) — 2Q11 SOLID QUARTER, RAISING FY11
ESTIMATE— reprinted from 08/01/2011

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ENTERGY CORPORATION (ETR-NYSE) — QUICK ALERT: VERMONT YANKEE INJUNCTION
DENIED — reprinted from 07/19/2011

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August 2011
NISOURCE, INC. (NI-NYSE) — QUICK ALERT: INCREMENTAL SETTLEMENT PROGRESS IN
INDIANA — reprinted from 07/13/2011

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August 2011

CENTRAL VERMONT PUBLIC SERVICE CORPORATION (CV-NYSE) — QUICK ALERT: CV
ACCEPTS GAZ METRO’S MODESTLY HIGHER OFFER — reprinted from 07/12/2011

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August 2011

PINNACLE WEST CAPITAL CORPORATION (PNW-NYSE) — TAKEAWAYS FROM INVESTOR
MEETINGS — reprinted from 07/06/2011

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NISOURCE, INC. (NI-NYSE) — INVESTOR MEETING TAKEAWAYS — reprinted from 06/22/2011

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PINACLE WEST CAPITAL CORPORATION (PNW-NYSE) — RATE CASE FILING SEEKS TO
MAINTAIN CONSTRUCTIVE RATEMAKING — reprinted from 06/02/2011

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION (CV-NYSE) — QUICK ALERT: SELLS
FOR SIGNIGICANT PREMIUM — reprinted from 05/30/2011

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APPENDIX
Table 8. Water Supply Forecast
(% of Average)

2009 2010 2011
Runoff Period (April - Sept.) Jan Feb Mar Apr May Jun July Jan Feb Mar Apr May Jun July Jan Feb Mar Apr May Jun July

Snowpack
Idaho
Upper Snake River Basin 93 93 89 97 108 69 NA 56 63 57 56 58 87 NA 129 113 106 119 161 283 NA
Panhandle Region Basin 69 80 76 90 91 89 NA 60 58 52 55 60 65 NA 91 95 105 112 142 200 NA
Oregon
Upper John Day Basin 81 73 72 97 70 NA NA 72 80 84 76 66 NA NA 143 98 79 125 217 NA NA
Upper Deschutes Basin 128 101 94 120 120 76 NA 90 71 60 67 85 123 NA 149 101 109 137 164 273 NA
Washington
Spokane River Basin 81 83 83 139 97 68 NA 56 57 52 51 54 51 NA 91 89 96 114 167 277 NA

Precipitation
Idaho
Upper Snake River Basin 96 70 126 130 85 261 60 75 38 57 140 120 221 43 86 76 163 201 158 149 77
Panhandle Region Basin 97 61 144 74 106 61 101 64 43 85 133 134 197 63 126 107 165 244 138 107 40
Oregon
Upper John Day Basin 64 61 143 98 110 150 28 102 59 59 109 169 222 50 85 87 160 135 208 138 35
Upper Deschutes Basin 60 67 121 77 130 119 10 81 53 83 129 127 234 47 76 84 169 141 144 356 107
Washington
Spokane River Basin 102 67 144 69 109 72 99 64 46 78 139 139 207 52 140 110 167 241 147 125 28

Reservoir Storage
Idaho
Upper Snake River Basin 100 104 112 105 103 114 113 115 115 120 126 106 113 106 100 98 98 89 85 104 136
Panhandle Region Basin 102 99 104 112 106 103 103 103 106 111 118 105 102 101 121 113 111 91 77 105 102
Oregon
Upper Deschutes Basin 114 106 102 103 105 112 111 110 107 106 105 102 109 106 112 111 106 108 113 121 132
Washington
Spokane River Basin 83 62 86 98 97 99 98 47 41 55 73 85 101 100 182 60 105 81 155 97 104

Stream Flow
Avista Corp. (AVA)*
Clark Fork River (75%) - Whitehorse Rapids 90 88 87 97 96 95 92 77 70 64 60 61 66 74 102 108 113 124 140 157 159
Spokane River (25%) 88 82 81 101 97 115 108 83 57 53 52 55 65 76 101 101 109 126 151 170 176
Idacorp (IDA)
Snake River-Brownlee Reservoir 73 69 61 82 81 76 86 60 56 49 51 52 61 72 112 99 91 115 133 159 153
Note: NA - not available.
*AVA-owned hydroelectric generation is split approximately 75%/25% along Clark Fork/Spokane rivers.
Sources: Northwest River Forecast Center (NRFC), National Water and Climate Center (NWCC), U.S. Dept. of Agriculture Natural Resources and Conservation Service (NRCS)
as of August 25, 2011

Using observed and estimated sample data input into statistical regression models, a water supply forecast attempts to predict a volume of streamflow that might pass a point
on a river stream, typically during the spring and summer seasons. In the western United States, snowfall accumulation (or snowpack) in the mountains during winter and
early spring becomes the source of much of the water run-off into riverstreams during the spring and summer snowmelt season. On certain mountain slopes in the Cascades
or Rocky Mountains, however, future precipitation may be a more dominant driver of actual streamflow than snowmelt, thus making forecasting more difficult. While no
prediction or model is perfect, streamflow forecasts can be important to operational river users (such as hydroelectric dam operators, fishermen or even white-water rafters)
who make decisions based on projected river conditions.

As a service to our clients, we track the April through September streamflow forecast issued by the Northwest River Forecast Center for companies under coverage (Avista
and IDACORP) that have large exposure to hydrological river conditions throughout the year. We believe investors may find incremental value in these forecasts as a possible
variable of earnings for the year, offset by any fuel/power supply cost adjustment mechanisms each utility may have to address hydrology variability. The percent-of-average
number listed in the table above is only a "probable" forecast within a forecasted range assuming unobstructed seasonal flow of water. In reality, water is stored in reservoirs
as it flows down the river basin, where the force of falling water is used to generate electricity. Unknown or unpredictable weather variables, uncertainty in the regression
models, and unforeseen changes are other factors to consider that could affect the accuracy of the water supply forecast.

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Table 9. Domestic Generation Capacity for KBCM Utilities Coverage List

Oper. Generating Plants by Fuel Type Capacity
Company Ticker Capacity(MW) Coal Nuclear Gas Oil Hydro Wind Other Reported
Owned: 58% 7% 27% 3% 5% 0% 0% 100% Ameren Corp. AEE 17,194 Used: 84% 12% 1% 0% 4% 0% 0%
Owned: 67% 6% 25% 0% 2% 1% 0% 100% American Electric Power, Inc. AEP 37,143 Used: 81% 9% 8% 0% 1% 1% 0%
Owned: 12% 0% 29% 0% 57% 0% 3% 100% Avista Corp. AVA 1,905 Used: 24% 0% 23% 0% 48% 0% 4%
Owned: 38% 0% 47% 0% 14% 0% 1% 100% CMS Energy, Inc. CMS 7,630 Used: 78% 0% 14% 0% 7% 0% 2%
Owned: 0% 19% 0% 34% 38% 0% 9% 100% Central Vermont Public Service
Corp. CV 114 Used: 0% 39% 0% 1% 48% 0% 13%
Owned: 24% 0% 76% 0% 0% 0% 0% 100% Cleco Corp. CNL 4,591 Used: 48% 0% 52% 0% 0% 0% 0%
Owned: 0% 0% 46% 54% 0% 0% 0% 100% Consolidated Edison, Inc ED 806 Used: 0% 0% 71% 29% 0% 0% 0%
Owned: 71% 0% 27% 1% 0% 0% 0% 100% DPL Inc. DPL 3,975 Used: 99% 0% 1% 0% 0% 0% 0%
Owned: 60% 9% 20% 3% 8% 0% 0% 98% DTE Energy Co. DTE 12,209 Used: 80% 16% 1% 0% 2% 0% 0%
Owned: 29% 22% 27% 12% 8% 1% 0% 100% Dominion Resources, Inc. D 27,156 Used: 39% 41% 14% 1% 3% 1% 0%
Owned: 45% 14% 28% 2% 9% 2% 0% 100% Duke Energy Corp. DUK 37,687 Used: 61% 28% 6% 0% 3% 1% 0%
Owned: 8% 34% 58% 0% 0% 0% 0% 100% Entergy Corp. ETR 30,408 Used: 13% 65% 23% 0% 0% 0% 0%
Owned: 6% 68% 10% 7% 7% 1% 0% 100% Exelon Corp. EXC 24,999 Used: 5% 92% 1% 0% 2% 0% 0%
Owned: 68% 18% 9% 0% 5% 0% 0% 90% FirstEnergy Corp FE 15,502 Used: 74% 25% 0% 0% 1% 0% 0%
Owned: 57% 8% 25% 8% 0% 2% 0% 100% Great Plains Energy, Inc. GXP 6,720 Used: 80% 17% 1% 0% 0% 1% 0%
Owned: 30% 0% 13% 0% 58% 0% 0% 100% IDACORP, Inc. IDA 3,474 Used: 47% 0% 1% 0% 51% 0% 0%
Owned: 70% 0% 22% 0% 0% 9% 0% 100% MDU Resources Group, Inc. MDU 569 Used: 96% 0% 0% 0% 0% 4% 0%
Owned: 2% 13% 48% 21% 0% 15% 0% 100% NextEra Energy, Inc. NEE 43,443 Used: 4% 27% 52% 6% 0% 10% 0%
Owned: 80% 0% 20% 0% 0% 0% 0% 97% NiSource Inc. NI 3,939 Used: 90% 0% 10% 0% 0% 0% 0%
Owned: 77% 0% 14% 9% 0% 0% 0% 100% Northwestern Corp. NWE 564 Used: 100% 0% 0% 0% 0% 0% 0%
Owned: 52% 13% 22% 9% 4% 0% 0% 100% PPL Corp. PPL 18,223 Used: 57% 30% 6% 1% 5% 0% 0%
Owned: 0% 0% 67% 33% 0% 0% 0% 100% Pepco Holdings, Inc. POM 3,750 Used: 0% 0% 90% 10% 0% 0% 0%
Owned: 27% 18% 54% 0% 0% 0% 0% 100% Pinnacle West PNW 6,412 Used: 45% 34% 20% 0% 0% 0% 0%
Owned: 31% 17% 39% 12% 1% 0% 0% 100% Progress Energy, Inc. PGN 23,814 Used: 45% 23% 29% 3% 1% 0% 0%
Owned: 47% 8% 33% 5% 6% 0% 0% 100% Southern Company SO 44,267 Used: 57% 15% 25% 0% 3% 0% 0%
Owned: 39% 0% 61% 1% 0% 0% 0% 100% TECO Energy, Inc. TE 4,755 Used: 55% 0% 45% 0% 0% 0% 0%
Owned: 60% 0% 31% 6% 1% 2% 0% 100% Wisconsin Energy Corp. WEC 6,212 Used: 83% 0% 13% 0% 1% 2% 0%
Owned: 42% 9% 42% 1% 3% 2% 1% 100% Xcel Energy Inc. XEL 19,076 Used: 64% 18% 15% 0% 1% 0% 1%
Owned: 39% 11% 33% 8% 8% 1% 1% Total Capacity & Fuel Mix Averages 406,538 Used: 54% 18% 19% 2% 7% 1% 1%
Owned % = Operating Capacity (MW)
Used % = Net Generation (MWh)
Note: Data as of 2010 based on current ownership, rounded to nearest whole percentage. Totals may not sum to 100% due to rounding.
Source: SNL Power; Company data, KeyBanc Capital Markets Inc.
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Table 10. Nuclear Outage Days by Company

2Q10 2Q11 Difference
Company Ticker Units Total Units Total Units Total
Ameren Corp. AEE 1 57.7 1 1.0 (56.7)
American Electric Power Co., Inc. AEP 2 15.7 2 2.0 (13.7)
DTE Energy Company DTE 1 11.7 1 1.5 (10.3)
Dominion Resources, Inc. D 7 85.7 7 118.2 32.5
Duke Energy Corp. DUK 7 77.0 7 132.5 55.5
Entergy Corp. ETR 11 123.1 11 122.3 (0.8)
Exelon Corp. EXC 17 73.8 17 157.7 83.9
FirstEnergy Corp. FE 8 110.3 8 238.4 128.1
Great Plains Energy, Inc. GXP 4 103.2 4 76.2 (27.0)
NextEra Energy, Inc. NEE 1 0.0 1 89.9 89.9
PPL Corporation PPL 2 48.6 2 131.5 82.9
Pinnacle West Capital Corp. PNW 3 55.2 3 40.1 (15.1)
Progress Energy, Inc. PGN 5 215.3 5 121.0 (94.3)
Southern Company SO 6 73.2 6 63.0 (10.2)
Xcel Energy Inc. XEL 3 42.0 3 111.1 69.2
Other Companies Not Covered -- 26 203.6 26 716.1 512.5
Total 104 1,296.1 104 2,122.4 0 826.2
Source: U.S. Nuclear Regulatory Commission (as of June 30, 2011), KeyBanc Capital Markets Inc. estimates

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Table 11. Cost Recovery Mechanisms

AMI / Smart Grid
Bad Debt /
Uncollectibles
Distribution / Delivery
Service Improvement
/ Reliability
DSM /
Energy Efficiency /
Conservation
Environmental
Fuel &
Purchased Power
Pension / OPEB
Revenue Decoupling
Storm Damage
Stranded Costs
Transmission / RTO
CWIP in Rate Base
Before
Plant In-Service
New Construction
AEE P1 X1, 2 X X X X1
AEP X1 X1, 3 X1 X1 X X1, 4 X1 G1
AVA X X1 X1
CMS X P X P P
CV X X
CNL X X G
ED X X X X X5
DPL P X X X X X4
DTE P X X X X X P X6
D P1 X1 P1 X X X X4
DUK X1 X1 X1 X1 X X X1 X1 X6 X1 G, I, N
ETR X1 X X1 N
EXC P P1 X1 X1 X F X X1 X1
FE X1 X1, 3 X1 X1 X1 X1 X1, 6
GXP P1 X1 X1
IDA X1 X X P P1 G
MDU X X1
NEE X X X X X7 N, W, S
NI X1 X1 X1 X F, X1 F, X1
NWE X X1 F1
PPL P X P X X X X8
POM X1 X1 X1 X1 X1 X X1 X1 X X8 S
PNW X X X X G9
PGN X13 X X1 X P1 X1 X1 N
SO X1 X X X X1 N, G10
TE X X X X
WEC X X X6, 11
XEL P1 X1 X1 X1 X1 X6, 12 X1 W
Legend
F – filed by company for cost recovery treatment, regulatory acceptance and approval to be determined
P – plan, pilot, program or law approves cost recovery, but requires a separate plan filing or prudency review with regulators (usually outside of a general rate case)
X – active cost recovery mechanism, rate adjustment clause, rider, tracker, or specific rate provision
G, I, N, S, W – (G)eneral plant/pre-construction, (I)GCC, (N)uclear, (S)olar, (W)ind
Notes
1 Not in all jurdisdictions
2 Recovers 40% electric / 80% gas delivery costs (residential and commerical) as fixed nonvolumetric monthly charge in Illinois
3 Only recovers vegetation management costs
4 Recovers PJM-related costs
5 Recovers purchased pow er payments to NYISO
6 Recovers MISO-related costs
7 Florida allow s small projects less than 0.5% of a utility's plant in service as component of rate base
8 FERC-granted transmission line projects
9 Line extension fees
10 Alabama new generating facilities and Mississippi new baseload capacity
11 Defer transmission costs exceeding amounts in rates and earn WACC return on unrecovered transmission cost deferrals.
12 PSCo retail Transmission Cost Adjustment (TCA) - allow s for return on CWIP for transmission investments
13 Smart Grid recovery through the Energy Conservation Cost Recovery rider in Florida, DSM/EE rider in Carolinas Sources: compiled from Company reports and SEC regulatory filings, KeyBanc Capital Markets Inc. research
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Glossary Definitions – Cost Recovery Mechanisms

AMI / Smart Grid – Costs associated with Advanced Metering Infrastructure (AMI), Smart Grid and other related programs. A smart
grid uses smart meters to directly connect customers and suppliers of electricity to observe energy usage and pricing in real time.

Bad Debt / Uncollectibles – Bad debt and uncollectible expenses, which result from the customers’ inability to fulfill their obligation to
pay; thus, rendering a portion of receivables unable to be collected.

Distribution / Delivery Service Improvement / Reliability – Maintaining and safely distributing power from the utility company to the
customer; includes costs such as vegetation management and underground cables.

DSM / Energy Efficiency / Conservation – Costs associated with Demand-Side Management, energy conservation and efficiency
efforts, including programs that manage and/or reduce energy use by customers.

Environmental – Costs associated with environmental compliance and remediation, including the reduction of emissions in accordance
with current environmental laws.

Fuel & Purchased Power – Electric fuel and power supply costs, including natural gas and steam, in addition to costs for purchased
power energy and capacity.

IGCC – Integrated Gasification Combined Cycle, a power plant using synthesis gas formed from coal. This gas is used to power a gas
turbine whose waste heat is passed to a steam turbine system. IGCC has the potential to burn coal more cleanly.

Pension / OPEB – Cost recovery designed to minimize subsequent rate impacts from market value fluctuations of benefit plan assets
tied to pension / other post-employment benefits plans.

Revenue Decoupling – By cutting the direct link between revenue and level of sales volumes (using fixed charges), decoupling is
designed to eliminate the disincentive for utility companies to invest in energy efficiency or conservation programs.

Storm Damage – Costs associated with storm damages and restoration of the system.

Stranded Costs – Unrecoverable costs incurred by a utility in connection with providing services in a competitive market when
customers change power suppliers, thus leaving their original utility with debts that can no longer be paid by revenue from the
ratepayers for whom the plants served. Such costs may include costs for generation assets, purchased power costs, regulatory assets
and liabilities, and other investments.

Transmission / RTO – Costs associated with the transmission of electricity into and across a utility service territory for retail/wholesale
customers and/or the costs of providing regional transmission service through a Regional Transmission Organization.

Construction-Related:
CWIP in Rate Base (Construction-Work-In-Progress in Rate Base) – Regulatory concept under which, in limited circumstances, a
regulatory body allows accelerated or early recovery into a company’s rate base of accrued costs for plants under construction but not
yet used and useful (in service) to serve ratepayers.

New Construction – Within the Company’s footprint, these programs promote policy/project development with alternative cost
recovery incentives associated with new Nuclear, Wind, IGCC, Solar, or other General plant, property, or equipment (PPE) / pre-
construction costs (may use “CWIP in Rate Base” as one method of accelerated regulatory recovery).
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KeyBanc Capital Markets Inc. Disclosures and Certifications

Important disclosures for the companies mentioned in this report can be found at https://key.bluematrix.com/Disclosure.

Reg A/C Certification
The research analyst(s) responsible for the preparation of this research report certifies that:(1) all the views expressed in this research report accurately
reflect the research analyst's personal views about any and all of the subject securities or issuers; and (2) no part of the research analyst's
compensation was, is, or will be directly or indirectly related to the specific recommendations or views expressed by the research analyst(s) in this
research report.

Rating System:
BUY - The security is expected to outperform the market over the next six to 12 months; investors should consider adding the security to their holdings
opportunistically, subject to their overall diversification requirements.

HOLD - The security is expected to perform in line with general market indices over the next six to 12 months; no buy or sell action is recommended at
this time.

UNDERWEIGHT - The security is expected to underperform the market over the next six to 12 months; investors should reduce their holdings
opportunistically.

The information contained in this report is based on sources considered to be reliable but is not represented to be complete and its accuracy is not
guaranteed. The opinions expressed reflect the judgment of the author as of the date of publication and are subject to change without notice. This
report does not constitute an offer to sell or a solicitation of an offer to buy any securities. Our company policy prohibits research analysts and members
of their families from owning securities of any company followed by that analyst, unless otherwise disclosed. Our officers, directors, shareholders and
other employees, and members of their families may have positions in these securities and may, as principal or agent, buy and sell such securities
before, after or concurrently with the publication of this report. In some instances, such investments may be inconsistent with the opinions expressed
herein. One or more of our employees, other than the research analyst responsible for the preparation of this report, may be a member of the Board of
Directors of any company referred to in this report. The research analyst responsible for the preparation of this report is compensated based on various
factors, including the analyst’s productivity, the quality of the analyst’s research and stock recommendations, ratings from investor clients, competitive
factors and overall Firm revenues, which include revenues derived from, among other business activities, the Firm’s performance of investment banking
services. In accordance with industry practices, our analysts are prohibited from soliciting investment banking business for our Firm.

Investors should assume that we are seeking or will seek investment banking or other business relationships with the company described in this report.

Rating Disclosures
Distribution of Ratings/IB Services Firmwide and by Sector
KeyBanc Capital Markets
IB Serv./Past 12 Mos.
Rating Count Percent Count Percent

BUY [BUY] 199 47.60 46 23.12
HOLD [HOLD] 211 50.50 51 24.17
SELL [UND] 8 1.90 0 0.00

ENERGY
IB Serv./Past 12 Mos.
Rating Count Percent Count Percent

BUY [BUY] 26 43.30 15 57.69
HOLD [HOLD] 34 56.70 20 58.82
SELL [UND] 0 0.00 0 0.00