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Home My WebLink AboutKeyBanc-3Q-2011.pdfI Energy Industry Research Electric Utilities Quarterly 3Q11 3Q11 Earnings 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 December 2011 Paul T. Ridzon (216) 689-0270 pridzon@keybanccm.com Timothy Yee (216) 689-0385 tyee@keybanccm.com For important disclosures and certifications, please refer to page 43 of this document. KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 2 of 43 December 2011 Contents 3Q11 RESULTS — BY THE NUMBERS...................................................................................................................................................................3 Earnings Comparison............................................................................................................................................................................4 Earnings Surprises ................................................................................................................................................................................4 Earnings Adjustments............................................................................................................................................................................4 Stock Price Performance.......................................................................................................................................................................5 Weather.................................................................................................................................................................................................6 3Q11 RATINGS, PRICE TARGET, AND RESEARCH COVERAGE CHANGES......................................................................................7 Rating Changes.....................................................................................................................................................................................7 Price Target Changes............................................................................................................................................................................7 Research Coverage Changes ...............................................................................................................................................................7 SECTOR OUTLOOK..................................................................................................................................................................................7 Historical Valuations Remain Inconclusive ............................................................................................................................................9 GROUP INVESTMENT THESIS ..............................................................................................................................................................11 INDUSTRY THEMES...............................................................................................................................................................................12 Retreating Commodity Prices and Available Capacity Heat Up Competition.......................................................................................12 Heightened Importance of Regulatory Success...................................................................................................................................12 Comprehensive Energy Reform at an Impasse; EPA Emissions Rules March Forward .....................................................................12 State Renewable Portfolio Standards..................................................................................................................................................13 Stock Performance Divergence Based on Commodity Exposure........................................................................................................15 Japan Nuclear Crisis Highlights Risks to Nuclear Power Industry.......................................................................................................16 New Generation / Transmission Build to Meet Load Growth ...............................................................................................................17 Cost Escalation in New Generation Build............................................................................................................................................17 Fifteen Percent Dividend Tax Rate Extension .....................................................................................................................................18 M&A ACTIVITY ON THE RISE................................................................................................................................................................19 Possible Acquirees..............................................................................................................................................................................19 Possible Acquirers...............................................................................................................................................................................19 Recent M&A Activity Update................................................................................................................................................................19 SHORT INTEREST OVERVIEW..............................................................................................................................................................21 ETR - QUICK ALERT: TRANSMISSION TO BE SPUN AND MERGED WITH ITC— reprinted from 12/05/2011................................23 EEI CONFERENCE DAY 1 HIGHLIGHTS; POST-3Q11 EARNINGS ESTIMATE CHANGES— reprinted from 11/08/2011................24 TE: 3Q11 QTR IN LINE; FINDS NEW MET COAL RESERVE— reprinted from 11/03/2011................................................................27 ELECTRIC UTILITIES INDUSTRY: 3Q11 EARNINGS AND WEATHER PREVIEW— reprinted from 10/23/2011 ..............................30 ELECTRIC UTILITIES INDUSTRY: EPA SAID TO BE BACKING OFF CSAPR— reprinted from 10/05/2011....................................31 IDA: POSITIVE EVENTS SET TABLE FOR NEXT ROUND OF REGULATION; UPGRADE TO BUY— reprinted from 10/03/2011 ..32 IDA - QA: UNICAP APPROVAL ACHIEVED, UNCERTAINTY REMOVED— reprinted from 09/16/2011............................................35 CNL: NOTES FROM THE ROAD; MERCHANT OUTLOOK IMPROVES— reprinted from 09/16/2011 ...............................................36 EASTERN UTILITIES DODGE A BULLET, IRENE IMPACTS LESS THAN FEARED— reprinted from 08/29/2011...........................39 APPENDIX...............................................................................................................................................................................................40 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 3 of 43 December 2011 Electric Utilities Quarterly 3Q11 INDUSTRY UPDATE Paul T. Ridzon: (216) 689-0270 — pridzon@keybanccm.com Timothy Yee: (216) 689-0385 — tyee@keybanccm.com 3Q11 RESULTS — BY THE NUMBERS Overall, companies within our electric utilities coverage universe reported mixed to higher 3Q11 results, driven by summer storm and weather impacts, weak merchant power prices, cost management, newer regulated rates, sluggish to modest retail load growth and tax benefits. As indicated in Table 1, aggregate 3Q11 earnings for stocks in the KeyBanc Capital Markets Inc. Electric Utility Index were up 6.8% on average, compared to the same quarter a year ago. Based on our estimates, we had initially anticipated an average quarterly earnings increase of 4.3%, so 3Q11 results were ahead of our expectations, largely due to summer weather and tax items. Table 1. Earnings Comparison Company Ticker 3Q11E 3Q11A 3Q10A 3Q Change 2011E 2012E Ameren Corp. AEE $1.30 $1.57 $1.40 12.1% $2.55 $2.35 American Electric Power, Inc. AEP $1.17 $1.17 $1.15 1.7% $3.15 $3.20 Avista Corp. AVA $0.18 $0.18 $0.22 (18.2)% $1.80 $1.75 CMS Energy, Inc. CMS $0.50 $0.53 $0.52 1.9% $1.45 $1.55 Central Vermont Public Service Corp. CV $0.70 $0.38 $0.79 (51.9)% $1.65 $1.80 Cleco Corp. CNL $1.00 $1.09 $0.83 31.3% $2.45 $2.40 Consolidated Edison, Inc ED $1.36 $1.33 $1.32 0.8% $3.60 $3.70 DTE Energy Co. DTE $1.11 $1.07 $0.96 11.5% $3.60 $3.75 Dominion Resources, Inc. D $0.92 $0.95 $1.03 (7.8)% $3.15 $3.30 Duke Energy Corp. DUK $0.48 $0.50 $0.51 (2.0)% $1.40 $1.40 Entergy Corp. ETR $3.53 $3.53 $2.76 27.9% $7.65 $5.90 Exelon Corp EXC $1.12 $1.12 $1.11 0.9% $4.20 $3.00 FirstEnergy Corp FE $1.24 $1.34 $1.28 4.7% $3.40 $3.30 Great Plains Energy, Inc. GXP $0.85 $0.91 $0.96 (5.2)% $1.30 $1.50 IDACORP, Inc. IDA $1.75 $2.16 $1.39 55.4% $3.40 $3.10 MDU Resources Group, Inc. MDU $0.34 $0.34 $0.41 (17.1)% $1.15 $1.35 NextEra Energy, Inc. NEE $1.43 $1.31 $1.45 (9.7)% $4.35 $4.55 NiSource, Inc. NI $0.12 $0.13 $0.06 116.7% $1.35 $1.45 Northwestern Corp. NWE $0.43 $0.41 $0.40 2.5% $2.35 $2.45 PPL Corp. PPL $0.69 $0.76 $0.74 2.7% $2.65 $2.50 Pepco Holdings, Inc. POM $0.38 $0.35 $0.52 (32.7)% $1.20 $1.30 Pinnacle West Capital Corp. PNW $2.17 $2.24 $2.06 8.7% $2.90 $3.35 Progress Energy, Inc. PGN $1.22 $1.16 $1.23 (5.7)% $3.10 $3.20 Southern Company SO $1.04 $1.07 $0.98 9.2% $2.55 $2.70 TECO Energy, Inc. TE $0.42 $0.42 $0.35 20.0% $1.30 $1.45 Wisconsin Energy Corp. WEC $0.50 $0.55 $0.47 17.0% $2.15 $2.30 Xcel Energy Inc. XEL $0.67 $0.69 $0.62 11.3% $1.70 $1.80 Average 6.8% Source: KeyBanc Capital Markets Inc. and Company reports KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 4 of 43 December 2011 EARNINGS COMPARISON Overall, companies within our electric utilities coverage universe reported mixed to higher 3Q11 results, driven by summer storm and weather impacts, weak merchant power prices, cost management, newer regulated rates, sluggish to modest retail load growth and tax benefits. As indicated in Table 1, aggregate 3Q11 earnings for stocks in the KeyBanc Capital Markets Inc. Electric Utility Index were up 6.8% on average, compared to the same quarter a year ago. Based on our estimates, we had initially anticipated average quarterly earnings increase of 4.3%, so 3Q11 results were ahead of our expectations, largely due to summer weather and tax items. EARNINGS SURPRISES On an individual company basis, there were two notable upside surprises and two notable downside surprises relative to our expectations for the quarter. On the upside, Ameren Corporation (AEE-NYSE; $1.57 vs. $1.40 in 3Q10; our estimate was $1.30, consensus was $1.29) beat our expectations driven by cost cutting, newer regulated rates and favorable weather-related sales. Great Plains Energy Incorporated (GXP-NYSE; $0.91 vs. $0.96 in 3Q10; our estimate was $0.85, consensus was $0.86) beat our expectations on higher gross margins and lower depreciation and amortization expense. Great Plains Energy also announced its first dividend increase since the Company cut its dividend in half in early 2009. On the downside, NextEra Energy, Inc. (NEE-NYSE; $1.31 vs. $1.45 in 3Q10; our estimate was $1.42, consensus was $1.41) reported disappointing 3Q earnings primarily due to lower earnings at its Texas retail supply business and power and gas trading results. NextEra Energy also issued 2012 earnings guidance ($4.35-$4.65 per share) that was below expectations. Central Vermont Public Service Corporation (CV-NYSE; $0.38 vs. $0.79 in 3Q10; our estimate was $0.70, consensus was $0.70) missed expectations on higher storm and service restoration costs related to tropical storm Irene and transmission expenses. Additionally, as highlighted in our 3Q11 quarterly earnings preview, we correctly predicted all of our earnings surprises (four upside; one downside) as American Electric Power, Inc. (AEP-NYSE; $1.17 vs. $1.15 in 3Q10, our estimate was $1.17, consensus was $1.15), DTE Energy Company ($1.07 vs. $0.96 in 3Q10, our estimate was $1.11, consensus was $1.00), IDACORP, Inc. (IDA-NYSE; $2.16 vs. $1.39 in 3Q10, our estimate was $1.75, consensus was $1.51) and Pinnacle West Capital Corporation (PNW-NYSE; $2.24 vs. $2.06 in 3Q10; our estimate was $2.17, consensus was $2.12) all beat to the upside, and Pepco Holdings, Inc. (POM-NYSE; $0.38 vs. $0.52 in 3Q10; our estimate was $0.35, consensus was $0.42) missed to the downside relative to consensus expectations. EARNINGS ADJUSTMENTS Heading into the 3Q11 earnings reporting season, we raised our 2011 estimates for AEE, ED, ETR, EXC, FE and NI, and lowered our 2011 estimates for MDU, NEE, NWE and TE. Additionally, we lowered our 2012 estimates for MDU and TE. For a summary on these estimate changes, please see page 31 for our October 23, 2011 published report titled “Electric Utilities Industry: 3Q11 Earnings and Weather Preview”. After digesting 3Q earnings reports, earnings conference calls and investor/analyst meetings, we further revised some earnings estimates. We raised 2011 estimates for AEE, CNL, ETR, EXC, FE, GXP, IDA, NWE, PPL and PNW, and lowered our 2011 estimates for AVA, DTE, D and NEE. Additionally, we raised our 2012 estimate for AEE and lowered our 2012 estimates for ETR and NEE. For a summary on these estimate changes, please see page 25 for our November 8, 2011 published report titled “EEI Conference Day 1 Highlights; Post-3Q11 Earnings Estimate Changes”. Table 1 lists the most current 2011 and 2012 earnings estimates for our companies under coverage. KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 5 of 43 December 2011 STOCK PRICE PERFORMANCE As shown in Table 2, stock price performance during 3Q11 for current companies under coverage in the KeyBanc Capital Markets Inc. Electric Utility Index was flat, with the index showing slight 0.5% price decline on average. Our coverage group’s performance was slightly below the Philadelphia Utility Index (UTY), which was up 0.8% in 3Q11, while our sector significantly outperformed the broader S&P 500 Index (SPX), which was down 14.3% for the quarter. Year-to-date, our sector index price performance of a 9.1% gain (UTY) has outperformed a loss of 1.7% in the broader market (SPX). We attribute sector strength and outperformance to investors becoming defensive while assessing the global issues with respect to European sovereign debt and global economic growth toward the end of the 3Q and even more recently pronounced toward the end of 2011. Table 2. Price Performance Price Price Price Price 3Q11 12/12/11 Company Ticker 12/31/10 6/30/11 9/30/11 12/12/11 Change YTD Change Ameren Corp. AEE 28.19 28.84 29.77 31.89 3.2% 13.1% American Electric Power, Inc. AEP 35.98 37.68 38.02 39.32 0.9% 9.3% Avista Corp. AVA 22.52 25.69 23.85 25.28 (7.2)% 12.3% CMS Energy, Inc. CMS 18.60 19.69 19.79 20.61 0.5% 10.8% Central Vermont Public Service Corp. CV 21.86 36.15 35.21 35.18 (2.6)% 60.9% Cleco Corp. CNL 30.76 34.85 34.14 35.87 (2.0)% 16.6% Consolidated Edison, Inc ED 49.57 53.24 57.02 58.82 7.1% 18.7% DTE Energy Co. DTE 45.32 50.02 49.02 51.93 (2.0)% 14.6% Dominion Resources, Inc. D 42.72 48.27 50.77 50.31 5.2% 17.8% Duke Energy Corp. DUK 17.81 18.83 19.99 20.61 6.2% 15.7% Entergy Corp. ETR 70.83 68.28 66.29 70.82 (2.9)% (0.0)% Exelon Corp EXC 41.64 42.84 42.61 43.06 (0.5)% 3.4% FirstEnergy Corp FE 37.02 44.15 44.91 44.16 1.7% 19.3% Great Plains Energy, Inc. GXP 19.39 20.73 19.30 20.97 (6.9)% 8.1% IDACORP, Inc. IDA 36.98 39.50 37.78 40.43 (4.4)% 9.3% MDU Resources Group, Inc. MDU 20.27 22.50 19.19 20.78 (14.7)% 2.5% NextEra Energy, Inc. NEE 51.99 57.46 54.02 56.99 (6.0)% 9.6% NiSource, Inc. NI 17.62 20.25 21.38 21.87 5.6% 24.1% Northwestern Corp. NWE 28.83 33.11 31.94 33.85 (3.5)% 17.4% PPL Corp. PPL 26.32 27.83 28.54 28.84 2.6% 9.6% Pepco Holdings, Inc. POM 18.25 19.63 18.92 19.41 (3.6)% 6.4% Pinnacle West Capital Corp PNW 41.45 44.58 42.94 46.22 (3.7)% 11.5% Progress Energy, Inc. PGN 43.48 48.01 51.72 53.70 7.7% 23.5% Southern Company SO 38.23 40.38 42.37 44.21 4.9% 15.6% TECO Energy, Inc. TE 17.80 18.89 17.13 18.20 (9.3)% 2.2% Wisconsin Energy Corp. WEC 29.43 31.35 31.29 32.70 (0.2)% 11.1% Xcel Energy Inc. XEL 23.55 24.30 24.69 25.91 1.6% 10.0% KBCM Electric Utility Index Average (0.5)% 13.2% Benchmarks: Philadelphia Utility Index UTY 421.84 447.79 451.24 460.12 0.8% 9.1% S&P 500 Index SPX 1257.64 1320.64 1131.42 1,236.47 (14.3)% (1.7)% Note: Past results cannot and should not be viewed as indicators of future performance. Source: FactSet KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 6 of 43 December 2011 WEATHER As the 3Q is typically a high cooling demand period, we would expect weather to be a significant earnings driver this quarter. By our weather tracking estimates, the nation still experienced above-normal summer temperatures in 3Q11, but fewer cooling degree days compared to the same quarter a year ago when it was the fourth hottest summer on record. Nationally, New Mexico and Texas had record warm temperatures, and the Northeast, Rocky Mountain and Western regions experienced much above-normal temperatures. No state had below-normal temperatures during 3Q11. The Northeast region had record rainfall during the period, while precipitation across the rest of the United States was varied. Table 3 shows the impact of the weather temperatures (primarily on retail delivery) in the quarter compared to our predictions. Table 3. 3Q11 Weather Impact — Cooling Degree Days Company Ticker 3Q11 vs. Normal 3Q11 vs. 3Q10 Estimated Same Qtr YOY EPS Impact Actual Same Qtr YOY EPS Impact Ameren Corp. AEE 26.3 % 0.8 % ($0.03) $0.02 American Electric Power, Inc. AEP 28.8 % 2.4 % $0.03 $0.02 CMS Energy Corp.* CMS 53.1 % (5.9)% ($0.02) $0.00 Cleco Corp. CNL 12.9 % (3.1)% ($0.01) $0.02 Dominion Resources, Inc. D 23.3 % (4.7)% ($0.02) ($0.02) Duke Energy, Inc. DUK 21.6% (8.1)% ($0.02) ($0.03) Entergy Corp. ETR 15.4% (1.4)% ($0.01) $0.00 Exelon Corp. EXC 27.8 % (8.4)% ($0.03) ($0.02) Great Plains Energy GXP 15.6 % (6.2)% ($0.04) ($0.03) NextEra Energy, Inc. NEE 8.7 % (1.5)% ($0.02) n/a NiSource, Inc. NI 28.7 % (2.8)% ($0.01) ($0.01) Pinnacle West Capital Corp. PNW 18.2 % 3.2 % $0.03 $0.10 Southern Company SO 12.1 % (9.3)% ($0.03) ($0.07) TECO Energy, Inc. TE 11.4 % 0.3 % ($0.03) ($0.02) Wisconsin Energy Corp. WEC 61.2 % (5.4)% ($0.02) ($0.03) Xcel Energy, Inc. XEL 46.4 % 14.5 % $0.03 $0.03 N/A – not readily available from company data * Decoupled 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 43 December 2011 3Q11 RATINGS, PRICE TARGET, AND RESEARCH COVERAGE CHANGES RATING CHANGES While there were no ratings actions during the 3Q11 calendar quarter, we have since upgraded IDACORP, Inc. (IDA-NYSE) to BUY from HOLD on October 3, 2011 (see our previously published report titled “IDA: Positive Events Set Table for Next Round of Regulation; Upgrade to BUY”). Our current research for companies under coverage published since our 2Q11 Electric Utilities Quarterly through the date of this publication is provided on pages 24-40. 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 $38.00 BUY $36.00 09/16/2011 IDA BUY $41.50 HOLD N/A 10/03/2011 MDU BUY $24.00 BUY $26.50 02/07/2011 Source: KeyBanc Capital Markets Inc. RESEARCH COVERAGE CHANGES With the close of the acquisition of DPL Inc. by AES Corporation, we terminated our research coverage of DPL on November 28, 2011. Effective upon termination of coverage, the last rating issued for this company (HOLD) should not be relied upon going forward. SECTOR OUTLOOK In the near term we expect that utilities will perform moderately well on a relative basis given the defensive nature of the group against a backdrop of significant uncertainty and market volatility around Eurozone concerns. 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. On a more normalized basis, in the 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. 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 3Q11 earnings conference calls cautioned slow to moderating load growth into 2012 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 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 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 8 of 43 December 2011 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. 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. Early in 2011, the group’s stock performance appeared to reflect optimistic economic recovery projections in the broader market, as our sector underperformed S&P 500 in the first half of the year. As broader market recovery became longer-dated, more challenged and subject to external shocks, such as Japan’s natural and nuclear disaster and European sovereign debt issues, 2H11 stock performance for our group appears to be driven by investor attractiveness to the safe and defensive qualities our sector provides relative to the broader market. We expect the group’s stock performance in 2012 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., Dominion Resources, Inc., Entergy Corporation, Exelon Corporation, FirstEnergy Corp., NextEra Energy, Inc. and PPL Corporation. Signs of a strong fundamental economic recovery in 2012 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 dampening 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 as well as tax policy and political election implications in 2012. Conversely, well positioned unregulated generators (nuclear or clean baseload) stand to benefit from the EPA regulations as forced retirement of antiquated and high emitting plants will remove capacity and drive a tighter market. We expect the interplay of low natural gas prices and reduced capacity will be noteworthy. Chart 1. YTD Performance of UTY vs. SPX (December 31, 2010 – December 12, 2011) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov -15-15 -10-10 -5-5 00 55 1010 1515 Re t u r n % Re t u r n % UTY vs. S&P 500 Indexed Price Performance - YTD 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 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 9 of 43 December 2011 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. Chart 2. Price Performance of S&P Electric Companies and 30-Year Treasury Bond Yield (December 31, 1996 – December 12, 2011) Ja n - 9 7 Ap r - 9 7 Ju l - 9 7 Oc t - 9 7 Ja n - 9 8 Ap r - 9 8 Ju l - 9 8 Oc t - 9 8 Ja n - 9 9 Ap r - 9 9 Ju l - 9 9 Oc t - 9 9 Ja n - 0 0 Ap r - 0 0 Ju l - 0 0 Oc t - 0 0 Ja n - 0 1 Ap r - 0 1 Ju l - 0 1 Oc t - 0 1 Ja n - 0 2 Ap r - 0 2 Ju l - 0 2 Oc t - 0 2 Ja n - 0 3 Ap r - 0 3 Ju l - 0 3 Oc t - 0 3 Ja n - 0 4 Ap r - 0 4 Ju l - 0 4 Oc t - 0 4 Ja n - 0 5 Ap r - 0 5 Ju l - 0 5 Oc t - 0 5 Ja n - 0 6 Ap r - 0 6 Ju l - 0 6 Oc t - 0 6 Ja n - 0 7 Ap r - 0 7 Ju l - 0 7 Oc t - 0 7 Ja n - 0 8 Ap r - 0 8 Ju l - 0 8 Oc t - 0 8 Ja n - 0 9 Ap r - 0 9 Ju l - 0 9 Oc t - 0 9 Ja n - 1 0 Ap r - 1 0 Ju l - 1 0 Oc t - 1 0 Ja n - 1 1 Ap r - 1 1 Ju l - 1 1 Oc t - 1 1 2% 3% 4% 5% 6% 7% 8% 30 - Y r T - B o n d Y i e l d % -20% 0% 20% 40% 60% 80% 100% 120% 140% S& P E l e c t r i c U t i l i t y I n d e x R e t u r n % UTY vs. S&P 500 Indexed Price Performance - YTD S&P 500 / Electric Utilities -IND (UTY) United States Treasury Bond (30 Y) Yield 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. HISTORICAL VALUATIONS REMAIN INCONCLUSIVE The two primary valuation metrics used for the group paint two contradictory pictures. From a relative (to the broad market) P/E standpoint, the group looks somewhat expensive, driven by outperformance of the more regulated subset of the utility sector. We believe this outperformance is a flight to safety in response to heightened concerns about the domestic and global economies. We also note that earnings estimates for the S&P 500 have historically been somewhat volatile. Alternatively, from a yield spread (vs. United States treasuries) perspective, the group continues to look rather attractive. We believe this is a function of investor recognition and acceptance of the fact that these are truly extraordinary times and treasury yields are being held artificially and unsustainably low. We have been asked about the prospects for the group if yields started to rise. In our view, there would likely be a band of tolerance for treasury yields to rise before there was a corresponding sell-off of the utility group. In the near to intermediate term, we expect the current valuation metrics to remain somewhat unchanged as uncertainty continues in the markets. As we gain more clarity on stabilization (or further deterioration) in the European markets, we expect the group would become less range bound and be revalued. KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 10 of 43 December 2011 Chart 3. P/E and Relative P/E of UTY vs. S&P 500 Indices (December 31, 2005 – present) P/E and Relative P/E of UTY vs. S&P 500 Indices 8.0x 9.0x 10.0x 11.0x 12.0x 13.0x 14.0x 15.0x 16.0x 17.0x 18.0x 19.0x 20.0x De c - 0 5 Ma r - 0 6 Ju n - 0 6 Se p - 0 6 De c - 0 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 Se p - 0 8 De c - 0 8 Ma r - 0 9 Ju n - 0 9 Se p - 0 9 De c - 0 9 Ma r - 1 0 Ju n - 1 0 Se p - 1 0 De c - 1 0 Ma r - 1 1 Ju n - 1 1 Se p - 1 1 De c - 1 1 Date 12 - m o F o r w a r d P / E 0.65 0.70 0.75 0.80 0.85 0.90 0.95 1.00 1.05 1.10 1.15 1.20 1.25 Re l a t i v e P / E UTY Index S&P500 Relative P/E Source: Bloomberg and KeyBanc Capital Markets Inc. research Chart 4. Yield Spread 10-Yr U.S. Treasury vs S&P Electric Utilities (June 1993 – present) Yield Spread Between 10 Year Treasury and S&P Electrics -400 -300 -200 -100 0 100 200 300 400 6/1/1993 6/1/1995 6/1/1997 6/1/1999 6/1/2001 6/1/2003 6/1/2005 6/1/2007 6/1/2009 6/1/2011 Date Yie l d S p r e a d ( b p ) 10 Yr Spread Average Spread Source: Bloomberg and KeyBanc Capital Markets Inc. research KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 11 of 43 December 2011 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. 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 5 illustrates the longer-term trend toward lower regulated utility equity returns authorized by state Commissions. Chart 5. 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 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 12 of 43 December 2011 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 6). 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. Chart 6. 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 - 0 4 Ma r - 0 5 Ju n - 0 5 Se p - 0 5 De c - 0 5 Ma r - 0 6 Ju n - 0 6 Se p - 0 6 De c - 0 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 Se p - 0 8 De c - 0 8 Ma r - 0 9 Ju n - 0 9 Se p - 0 9 De c - 0 9 Ma r - 1 0 Ju n - 1 0 Se p - 1 0 De c - 1 0 Ma r - 1 1 Ju n - 1 1 Se p - 1 1 De c - 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, Duke 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. KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 13 of 43 December 2011 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. 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 timeframe. 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 14 of 43 December 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 15 of 43 December 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 7. 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 7. Price Performance of Different Utility Subgroups (December 31, 2006 – December 12, 2011) -55% -50% -45% -40% -35% -30% -25% -20% -15% -10% -5% 0% 5% 10% 15% 20% 25% 30% 35% 40% De c - 0 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 Se p - 0 8 De c - 0 8 Ma r - 0 9 Ju n - 0 9 Se p - 0 9 De c - 0 9 Ma r - 1 0 Ju n - 1 0 Se p - 1 0 De c - 1 0 Ma r - 1 1 Ju n - 1 1 Se p - 1 1 De c - 1 1 Date Re t u r n T&D Only Small Vertical Large Vertical S&P 500 Commodity 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. The smaller vertically integrated names had a period of meaningful outperformance, which we attribute to the April and May announcements of the acquisitions of DPL and CV, respectively. These gains were lost as severe market deterioration dampened M&A speculation (see Chart 8). KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 16 of 43 December 2011 Chart 8. Year-to-Date S&P 500 vs. KBCM Electric Utility Segment Performance (December 31, 2010 – December 12, 2011) -14% -12% -10% -8% -6% -4% -2% 0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 20% 22% 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 Se p - 1 1 Oc t - 1 1 No v - 1 1 De c - 1 1 Date Re t u r n Small Vertical T&D Only 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 17 of 43 December 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 9). Chart 9. Historical and Forecasted U.S. Electric Supply and Demand (Summer) 0 100000 200000 300000 400000 500000 600000 700000 800000 900000 1000000 1100000 1200000 19 8 9 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 F 20 1 1 F 20 1 2 F 20 1 3 F 20 1 4 F 20 1 5 F Date Lo a d ( M W ) 0% 5% 10% 15% 20% 25% 30% Ma r g i n 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 10 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 18 of 43 December 2011 Chart 10. Construction Materials Indexed Pricing 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230 240 250 260 270 280 290 1Q 0 5 2Q 0 5 3Q 0 5 4Q 0 5 1Q 0 6 2Q 0 6 3Q 0 6 4Q 0 6 1Q 0 7 2Q 0 7 3Q 0 7 4Q 0 7 1Q 0 8 2Q 0 8 3Q 0 8 4Q 0 8 1Q 0 9 2Q 0 9 3Q 0 9 4Q 0 9 1Q 1 0 2Q 1 0 3Q 1 0 4Q 1 0 1Q 1 1 2Q 1 1 3Q 1 1 4Q 1 1 F Date Re l a t i v e P r i 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. We expect current federal budget concerns will make the discussion more contentious than in the past. KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 19 of 43 December 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. 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. 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 2Q12 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 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 20 of 43 December 2011 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. 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, subject to regulatory approvals from Federal Energy Regulatory Commission (FERC), Nuclear Regulatory Commission (NRC), North Carolina Utilities Commission (NCUC) and South Carolina Public Service Commission (SCPSC). 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 43 December 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 in 2H11 (see Chart 11) 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 11. P/E Comparison of KBCM Utility Coverage vs. S&P 500 (December 31, 2010 – December 12, 2011) 10.5x 11.0x 11.5x 12.0x 12.5x 13.0x 13.5x 14.0x 14.5x 15.0x 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 Se p - 1 1 Oc t - 1 1 No v - 1 1 De c - 1 1 Date 12 m o F w d P / E 0.88 0.92 0.96 1.00 1.04 1.08 1.12 1.16 1.20 1.24 Re l a t i v e P / E KBCM Utility Index S&P500 Relative P/E 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 modestly increased through 3Q11, likely from increased shares and positioning due to M&A related activity, as well as our sector having outperformed the broader market. KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 22 of 43 December 2011 Table 7. Monthly Short Interest (days) (shares in millions) Shares Current 2011 2010 2009 Company Ticker Out Short Ratio Nov Oct Sep Aug Jul Jun May Apr Mar Feb Jan Dec Nov Oct Sep Aug Jul Jun May Apr Mar Feb Jan Dec Ameren Corp. AEE 242.2 2.6 4.7 4.6 7.2 5.5 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 482.9 1.6 4.8 6.3 5.9 8.5 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 58.2 5.3 2.1 2.0 2.4 2.5 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 253.6 5.3 13.5 17.6 15.0 15.8 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 11.4 0.6 0.6 0.6 0.5 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 60.7 7.3 3.5 3.4 3.8 3.8 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 6.6 10.7 11.2 11.9 13.5 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.1 DPL 117.7 1.0 0.9 1.3 1.5 1.3 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 1.9 1.7 2.2 2.0 2.4 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 569.6 2.4 7.1 7.9 10.9 11.4 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 1,332.7 5.0 52.0 48.5 51.6 48.6 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 176.1 3.4 4.1 3.2 3.3 3.5 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 663.0 8.5 36.6 31.2 26.0 23.0 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 1.4 3.7 4.1 5.2 4.4 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 136.1 6.3 5.7 6.7 6.3 5.3 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 49.8 7.1 1.8 1.7 2.0 2.0 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 2.6 1.8 1.4 1.3 1.6 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 422.5 3.4 7.1 6.0 5.6 5.6 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 281.1 1.9 5.0 3.9 4.4 6.1 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 6.9 1.4 1.6 1.7 1.8 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 578.3 2.2 12.9 14.6 16.5 14.6 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 227.0 5.2 9.2 8.1 9.9 11.4 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 109.2 2.0 1.9 1.8 1.9 2.2 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 295.0 1.7 2.2 2.7 4.3 4.4 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 861.9 3.7 13.9 13.3 15.2 12.2 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 215.8 5.1 7.9 6.9 7.5 6.9 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.2 WEC 231.3 4.5 6.4 6.5 7.1 7.2 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 485.0 2.4 5.1 4.8 6.4 6.0 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 8,968.5 228.2 224.1 237.3 231.8 212.2 202.4 200.9 191.3 159.7 185.6 189.6 188.5 204.6 219.0 250.6 261.9 251.3 224.2 216.3 202.8 208.6 195.6 201.4 217.0 Notes: 1) DPL research coverage terminated November 28, 2011. Information presented for historical comparison purposes only. 2) Historical share counts adjusted for WEC 2:1 stock split on March 1, 2011 Source: Bloomberg, December 12, 2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 23 of 43 December 2011 ENTERGY CORPORATION (HOLD) ETR - QUICK ALERT: TRANSMISSION TO BE SPUN AND MERGED WITH ITC— reprinted from 12/05/2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 24 of 43 December 2011 EEI CONFERENCE DAY 1 HIGHLIGHTS; POST-3Q11 EARNINGS ESTIMATE CHANGES— reprinted from 11/08/2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 25 of 43 December 2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 26 of 43 December 2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 27 of 43 December 2011 TECO ENERGY, INC.: TE: 3Q11 QTR IN LINE; FINDS NEW MET COAL RESERVE— reprinted from 11/03/2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 28 of 43 December 2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 29 of 43 December 2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 30 of 43 December 2011 ELECTRIC UTILITIES INDUSTRY: 3Q11 EARNINGS AND WEATHER PREVIEW— reprinted from 10/23/2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 31 of 43 December 2011 ELECTRIC UTILITIES INDUSTRY: EPA SAID TO BE BACKING OFF CSAPR— reprinted from 10/05/2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 32 of 43 December 2011 IDA: POSITIVE EVENTS SET TABLE FOR NEXT ROUND OF REGULATION; UPGRADE TO BUY— reprinted from 10/03/2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 33 of 43 December 2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 34 of 43 December 2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 35 of 43 December 2011 IDACORP, INC. (HOLD) IDA - QA: UNICAP APPROVAL ACHIEVED, UNCERTAINTY REMOVED— reprinted from 09/16/2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 36 of 43 December 2011 CLECO CORPORATION CNL: NOTES FROM THE ROAD; MERCHANT OUTLOOK IMPROVES— reprinted from 09/16/2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 37 of 43 December 2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 38 of 43 December 2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 39 of 43 December 2011 ENERGY: ELECTRIC UTILITIES EASTERN UTILITIES DODGE A BULLET, IRENE IMPACTS LESS THAN FEARED— reprinted from 08/29/2011 KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 40 of 43 December 2011 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. KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 41 of 43 December 2011 Table 9. Domestic Generation Capacity for KBCM Utilities Coverage List Oper. Capacity Generating Plants by Fuel Type Capacity Company Ticker (MW) Coal Nuclear Gas Oil Hydro Wind Other Reported Owned: 58% 7% 28% 2% 5% 0% 0% 100% Ameren Corp. AEE 17,450 Used: 84% 12% 1% 0% 4% 0% 0% Owned: 68% 6% 23% 0% 2% 1% 0% 100% American Electric Power, Inc. AEP 37,093 Used: 82% 9% 8% 0% 1% 1% 0% Owned: 11% 0% 30% 0% 56% 0% 3% 100% Avista Corp. AVA 1,931 Used: 24% 0% 23% 0% 48% 0% 4% Owned: 39% 0% 46% 0% 13% 0% 1% 100% CMS Energy, Inc. CMS 7,860 Used: 77% 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: 60% 9% 20% 3% 7% 0% 1% 100% DTE Energy Co. DTE 12,350 Used: 80% 16% 1% 0% 2% 0% 1% Owned: 28% 22% 27% 13% 8% 1% 0% 99% Dominion Resources, Inc. D 27,156 Used: 38% 41% 14% 2% 3% 1% 0% Owned: 45% 14% 28% 2% 9% 3% 0% 100% Duke Energy Corp. DUK 37,729 Used: 60% 28% 7% 0% 3% 1% 0% Owned: 8% 34% 58% 0% 0% 0% 0% 100% Entergy Corp. ETR 30,507 Used: 13% 64% 23% 0% 0% 0% 0% Owned: 6% 66% 10% 10% 6% 3% 0% 100% Exelon Corp. EXC 26,091 Used: 5% 92% 1% 0% 2% 0% 0% Owned: 61% 26% 8% 1% 4% 0% 0% 100% FirstEnergy Corp FE 15,628 Used: 64% 35% 0% 0% 1% 0% 0% Owned: 57% 8% 25% 8% 0% 2% 0% 100% Great Plains Energy, Inc. GXP 6,756 Used: 80% 17% 1% 0% 0% 1% 0% Owned: 29% 0% 13% 0% 57% 0% 0% 100% IDACORP, Inc. IDA 3,537 Used: 47% 0% 1% 0% 52% 0% 0% Owned: 69% 0% 21% 0% 0% 9% 1% 100% MDU Resources Group, Inc. MDU 576 Used: 94% 0% 0% 0% 0% 4% 1% Owned: 2% 12% 46% 21% 1% 17% 0% 100% NextEra Energy, Inc. NEE 45,729 Used: 4% 27% 51% 6% 1% 12% 0% Owned: 81% 0% 19% 0% 0% 0% 0% 100% 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: 51% 12% 21% 10% 5% 0% 0% 100% PPL Corp. PPL 19,023 Used: 57% 29% 6% 1% 8% 0% 0% Owned: 0% 0% 66% 34% 0% 0% 0% 100% Pepco Holdings, Inc. POM 4,804 Used: 0% 0% 89% 9% 0% 0% 2% Owned: 27% 18% 54% 0% 0% 0% 0% 100% Pinnacle West PNW 6,413 Used: 45% 34% 20% 0% 0% 0% 0% Owned: 31% 17% 39% 12% 1% 0% 0% 100% Progress Energy, Inc. PGN 23,798 Used: 45% 23% 29% 3% 1% 0% 0% Owned: 48% 8% 33% 5% 6% 0% 0% 100% Southern Company SO 44,270 Used: 57% 15% 25% 0% 3% 0% 0% Owned: 39% 0% 61% 1% 0% 0% 0% 100% TECO Energy, Inc. TE 4,755 Used: 56% 0% 44% 0% 0% 0% 0% Owned: 59% 0% 31% 6% 1% 2% 0% 100% Wisconsin Energy Corp. WEC 6,246 Used: 83% 0% 13% 0% 2% 2% 0% Owned: 42% 9% 42% 1% 3% 2% 1% 100% Xcel Energy Inc. XEL 18,855 Used: 64% 18% 15% 0% 1% 0% 1% Owned: 38% 11% 33% 8% 8% 1% 1% Total Capacity & Fuel Mix Averages 408,573 Used: 52% 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. KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 42 of 43 December 2011 Table 10. Nuclear Outage Days by Company 3Q10 3Q11 Difference Company Ticker Units Total Units Total Units Total Ameren Corp. AEE 1 0.0 1 0.3 0.3 American Electric Power Co., Inc. AEP 2 0.1 2 13.7 13.7 DTE Energy Company DTE 1 0.3 1 0.3 0.1 Dominion Resources, Inc. D 7 35.4 7 93.3 57.8 Duke Energy Corp. DUK 7 18.8 7 14.0 (4.8) Entergy Corp. ETR 11 63.7 11 18.7 (45.0) Exelon Corp. EXC 17 51.0 17 45.5 (5.6) FirstEnergy Corp. FE 8 35.5 8 15.5 (20.0) Great Plains Energy, Inc. GXP 4 0.7 4 0.9 0.2 NextEra Energy, Inc. NEE 1 0.0 1 3.2 3.2 PPL Corporation PPL 2 25.3 2 13.2 (12.1) Pinnacle West Capital Corp. PNW 3 0.2 3 9.0 8.8 Progress Energy, Inc. PGN 5 119.9 5 103.8 (16.0) Southern Company SO 6 5.6 6 26.1 20.6 Xcel Energy Inc. XEL 3 2.7 3 4.7 2.0 Other Companies Not Covered -- 26 88.6 26 256.6 168.0 Total 104 534.5 104 618.9 0 171.1 Source: U.S. Nuclear Regulatory Commission (as of Sept. 30, 2011), KeyBanc Capital Markets Inc. estimates KeyBanc Capital Markets Inc., Member NYSE/FINRA/SIPC Equity Research Page 43 of 43 December 2011 KeyBanc Capital Markets Inc. Disclosures and Certifications Important disclosures for the companies mentioned in this report can be found at https://key2.bluematrix.com/sellside/Disclosures.action. 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Please refer to the analysts' recently published reports for company-specific valuation and risks. 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] 232 46.80 46 19.83 HOLD [HOLD] 262 52.80 53 20.23 SELL [UND] 2 0.40 0 0.00 ENERGY IB Serv./Past 12 Mos. Rating Count Percent Count Percent BUY [BUY] 35 46.70 14 40.00 HOLD [HOLD] 40 53.30 20 50.00 SELL [UND] 0 0.00 0 0.00