Marc de Croisset FBR CAPITAL MARKETS & CO. Coal-to-Gas Switching: Distilling the Issue

Transcription

1 Marc de Croisset FBR CAPITAL MARKETS & CO. Coal-to-Gas Switching: Distilling the Issue September 20, 2012

2 Disclosures Important disclosures can be found at the end of this presentation. **Not to be used in lieu of full research report** This document was prepared on September 20, This document is provided on a confidential basis for the sole use of the recipient and may not be modified or forwarded without the approval of FBR. The information is provided for illustration purposes only and does not represent a recommendation or solicitation to buy or sell any security or an endorsement of any particular investment strategy. Research is provided by FBR Capital Markets & Co. Please see complete FBR Research reports concerning the subject issuers. All graphics/tables/photos/charts from company Web sites, FBR Research, and various Web sites. 2

3 Marc de Croisset Biography Marc de Croisset is an analyst and vice president in the energy & natural resources group at FBR Capital Markets & Co. (FBRC), covering the utilities sector. Prior to joining FBRC in October 2009, Mr. de Croisset was a vice president and senior analyst at Macquarie Capital, where he covered U.S.-regulated electric utilities. Some of his prior work includes a novel approach for hedging interest rate risk embedded in regulated electric utilities. More recently, Mr. de Croisset performed industry leading work on the impact of EPA regulation on electric utilities and coal-to-gas switching. Mr. de Croisset started his career in 1998 as a financial analyst in telecom investment banking at UBS and subsequently worked as an associate in private equity. Following business school, he joined Citigroup, where he covered electric utilities. In, Mr. de Croisset was ranked by StarMine as one of the top three analysts in the U.S. in the electric utilities industry for earnings estimate accuracy. Mr. de Croisset received his M.B.A. from the University of Virginia Darden School of Business, his M.A. in chemistry from Harvard University, and his B.A. in physics from the University of Chicago. 3

4 Coal-to-Gas Switching Hoax 4

5 What Is the Coal-to-Gas Switching Hoax? The Hoax The hoax scenario assumes that about 230 GW of CCGTs can increase their utilization from 42% to 60% at $2/MMBtu to $3/MMBtu gas. What would the world look like? Coal volumes would be hit by 200 million tons per year from. Natural gas demand would go up to 28 Bcf/day from 21 Bcf/day in. CCGTs would be running at their August 2009 peak ALL year. Generation Volumes 2008,, and the Hoax Year (TWh). Some predicted that natural gas generation can increase in 2012 as much as in the last 10 years combined??? 4,500 4,000 3,500 1,256 1,355 1,355 3,000 2,500 2,000 1,368 1,991 1,734 40%-50% 1,500 Increase 157 1, , The Hoax Gas - CCGT Gas - CT & Other Coal Other There is meaningfully more coal than CCGT capacity today. And a lot of the CCGT capacity that does exist today is not uniformly spread across the coal states. This constrains switching. A Capacity (GW) Other 326 Coal 327 Gas - CCGT 233 Gas - Other 215 Source: SNL and FBR Research

6 Jan-07 Mar-07 May-07 Jul-07 Sep-07 Nov-07 Jan-08 Mar-08 May-08 Jul-08 Sep-08 Nov-08 Jan-09 Mar-09 May-09 Jul-09 Sep-09 Nov-09 Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Bcf/Day $/MMBtu The Great Hoax Implies Peak Utilization All Year Seasonal Outlook We Expect Bcf/day of Switching in 2012 versus. This is above our initial base case of 2 Bcf/day and below our theoretical maximum of 4 Bcf/day in a $2/MMBtu gas environment. The max summer peaks have touched 29 Bcf/day to 30 Bcf/day in recent history. We expect the off-peaks to rise in a lower gas environment (as we have observed year to date) but the peaks to remain roughly the same Forecast Record Hot Weather Base Year Very Mild Winter $2.50/MMBtu Gas $3.50/MMBtu Gas Bcf/Day (EIA Estimate through May, EIA Short-term Forecast Thereafter) Bcf/Day (Adjusted for Weather, Recent Gas Prices and New Build) Bcf/Day (Adjusted for Weather and Recent Gas Prices) Natural Gas ($/MMBtu) Note: Light green represents EIA s estimate of gas burn through May 2012 and its forecast thereafter. The darker shades of green adjust for certain items such as weather, new build, and more up-to-date gas futures. We have not normalized January May of 2012 for weather, nuclear outages. and hydro conditions in this graph. Source: EIA, SNL, and FBR Research

7 Generation (Thousand MWh) Recent History Points to Limited Coal-to- Gas Switching Generation Waterfall New gas builds amplified the appearance of coal-to-gas switching between 2008 and. Excluding new builds, net gas switching was probably 1 Bcf/day to 1.5 Bcf/day. Up to 3 Bcf/day excluding cannibalization of gas. Coal Has Been Cannibalized by CCGTs, Renewables, and New Gas Capacity (roughly 20 GW since 2008) 4,200,000 About Bcf/Day Net 4,100,000 4,000, Bcf/Day About 3 Bcf/Day 3,900,000 3,800, Bcf/Day About 1.5 Bcf/day 3,700,000 3,600, Generation Coal 2008 CCGT Fleet That Decreased Generation 2008 Non- CCGT Fleet Petroleum Liquids Nuclear Petroleum Coke Other Hydroelectric Pumped Storage 2008 CCGT Fleet That Increased Generation Other Hydroelectric Renewables Conventional (Mostly Wind) New Gas Generation Note: Red represents declines in generation between 2008 and. Green represents increases in generation. Source: EIA, SNL, and FBR Research

8 The Constraints to Switching Appear High Gas Fleet Analysis Let recent history be your guide. Between 2008 and 2009, when gas prices were cut in half, only 40 GW to 70 GW of the gas generation fleet responded materially (5%+ utilization increase) and stayed there. In a given month at $2 gas, we have seen fast movers reach 70 GW to 100 GW. Also, in March 2012, only 27 GW of generation was operating at 80% utilization or more at ~$2 natural gas. Only 40 GW to 70 GW of Gas Generation Increased Its Utilization Sharply between 2008 and In 2009, Fast-Moving Gas Plants Increased Their Market Share of Gas Generation by 6% 7%. 60% 50% 40% 30% 20% 10% Fast Movers ~ 40GW Slower Movers ~ 340GW E 60% 50% 40% 30% 20% 10% Fast Movers ~ 40GW 13% 20% 19% 10% 9% 8% 26% 26% 24% 54% 42% 42% % Tier 1 (Fast Movers) Tier 2 (Aspirationals) Tier 3 (Slow Movers) Tier 4 (Dead Man Walking) 0% Tier 1 Tier 2 Tier 3 Tier 4 Source: SNL and FBR Research Source: SNL and FBR Research

9 Coal-to-Gas Switching Reality 9

10 Utilization (%) Natural Gas Price ($/MMBtu) Cooling Degree Days (CDD) Utilization (%) Summer Demand Trumps Natural Gas Price Signals Summer Analysis July August Demand Typically Trumps Natural Gas Price Signals. Our opinion is that coal-to-gas switching in the summer will be very limited, with utilization factors consistent with what we have observed in the past. Despite $2.00 $2.75 Gas in January March, CCGT Utilization Did Not Break July August Levels, and Non-CCGT Utilization Was Roughly One-Third to One-Half of Its Summer Potential 60% 50% 40% 30% 20% 10% 0% 35% 34% 31% 33% 33% Jan. Feb. Mar. Apr. May 41% Jun. 51% 52% 43% Jul. Aug. Sep. 37% 37% Oct. Nov. 42% 45% 48% 43% Dec. Jan Feb CCGT Utilization Non-CCGT Gas Utilization Henry Hub ($/Mcf) Mar August CCGT Utilization Has Been Highly Correlated with Weather, Not Natural Gas Prices $6/MMBtu Gas $8/MMBtu Gas Aug Aug Aug Aug Aug. CDD $3/MMBtu Gas CCGT Utilization $4/MMBtu Gas On-Peak CCGT Utilization Has Not Trended with Natural Gas Source: SNL, Bloomberg and FBR Research Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan CCGT Utilization Source: SNL and FBR Research Natural Gas Price

11 September December 2012 Gas Prices Similar to September December Levels Post-Summer Outlook Natural Gas Prices Are Higher in 2H12, and the YOY Natural Gas Price Delta Is Declining. In 1H12, natural gas prices were down about $2/MMBtu YOY. This resulted in Bcf/day of switching during that period. In the September December period, gas prices are averaging above $3/MMBtu, only $0.40 below the prior-year levels. As a result, we expect little switching after the summer period. Coal-to-Gas Switching Averaged Bcf/day in 1H12 When Gas was $2.37/MMBtu vs. $4.27/MMBtu in 1H11. Record mild weather Bcf/day YOY 1H12 Actual Gas Burn Increase 6.1 -Hydro/Nuke Conditions New Gas Plants Demand Normalized 0.4 Organic Coal-to-Gas Switching 4.9 Source: EIA and FBR Research Gas prices down $2/MMBtu YOY Jan-June: Bcf/day of switching September December Natural Gas Prices are Averaging About $3.05/MMBtu vs. $3.48/MMBtu in the Prior Year Month ($/MMBtu) 2012 YOY Delta January $4.48 $2.70 -$1.78 February $4.11 $2.52 -$1.59 March $3.96 $2.19 -$1.77 April $4.23 $1.95 -$2.28 May $4.31 $2.42 -$1.89 June $4.55 $2.45 -$2.11 July $4.62 $2.93 -$1.69 August $4.07 $2.86 -$1.20 September $3.91 $2.79 -$1.12 October $3.56 $2.99 -$0.57 November $3.25 $3.10 -$0.14 December $3.19 $3.32 $0.13 $2/MMBtu change = Bcf/day of switching Summer demand trumps gas price signals Similar gas prices as in the prior year = little switching July-Aug: Summer demand trumps price signals Sep-Dec: Easy gas price comps Gas prices down $0.40/MMBtu YOY Source: SNL and FBR Research Coal stock piles lower than in 1H12

12 FBR Forecast of U.S. Electricity Energy Mix Appendix Base Case: Coal Retirements Capacity GW) E 2013E 2014E 2015E Natural Gas Combined Cycle Combustion Turbine Other Natural Gas Coal Nuclear Other Total 1,007 1,020 1,030 1,037 1,051 1,068 1,080 1,101 1,124 1,141 1,148 1,150 Generation (million MWh) E 2013E 2014E 2015E Natural Gas Combined Cycle , ,057 1,109 Combustion Turbine Other Natural Gas ,017 1,181 1,144 1,184 1,232 Coal 1,959 2,007 1,995 2,020 1,991 1,769 1,861 1,734 1,567 1,602 1,562 1,526 Nuclear Other Total 3,906 4,017 4,051 4,142 4,112 3,953 4,138 4,106 4,065 4,126 4,167 4,209 Implied Utilization E 2013E 2014E 2015E Natural Gas Combined Cycle 33% 34% 36% 39% 38% 39% 41% 42% 49% 46% 46% 46% Combustion Turbine 5% 6% 6% 6% 5% 5% 6% 6% 5% 5% 4% 4% Other 18% 17% 15% 16% 16% 15% 15% 15% 15% 15% 14% 13% Natural Gas 20% 21% 22% 24% 23% 24% 25% 26% 29% 28% 28% 28% Coal 70% 72% 71% 72% 71% 63% 66% 61% 55% 57% 59% 61% Nuclear 88% 87% 87% 89% 89% 88% 89% 88% 87% 89% 89% 89% Other 29% 29% 29% 26% 26% 27% 27% 29% 26% 26% 27% 28% Total 44% 45% 45% 46% 45% 42% 44% 43% 41% 41% 41% 42% % of Generation Mix E 2013E 2014E 2015E Natural Gas Combined Cycle 13% 14% 16% 17% 17% 19% 20% 21% 25% 24% 25% 26% Combustion Turbine 2% 2% 2% 2% 2% 2% 2% 2% 2% 2% 1% 1% Other 3% 3% 2% 2% 2% 2% 2% 2% 2% 2% 2% 2% Natural Gas 18% 19% 20% 21% 21% 23% 23% 25% 29% 28% 28% 29% Coal 50% 50% 49% 49% 48% 45% 45% 42% 39% 39% 37% 36% Nuclear 20% 19% 19% 19% 19% 20% 19% 19% 19% 19% 19% 19% Other 12% 12% 12% 11% 11% 13% 12% 14% 13% 14% 15% 15% Total 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Source: SNL, EIA, and FBR Research

13 Industry Risks Level of interest rates affects valuation. There is a strong correlation between the trading multiples of regulated electric utilities and long-term interest rates. If long-term rates were to increase sharply, we would expect the trading multiples to contract. Capital plan execution risk. Regulated utilities may not complete their capital budgets or obtain timely recovery for them. This could have an adverse effect on earnings growth, cash flows, and valuation. Sufficient regulatory recovery is not guaranteed. Most of the regulated utilities operate on a rate-of-return/costof-service basis. If adequate recovery on invested capital is not achieved in a timely fashion, earnings and cash flows could be pressured. This could lead to dilutive equity issuances. Economic downturns reduce demand for electricity. Poor economic conditions typically result in weaker electricity sales and cash flows and affect the rate of delinquent customer accounts receivable. When industrial customers reduce production, there is a particularly large negative impact on electricity consumption. Potentially high environmental compliance costs associated with coal or carbon. Many utilities rely heavily on coal for electricity production and could face higher environmental compliance costs for carbon emissions or coal. While these costs will likely be passed through to customers for regulated utilities, we are not certain how much would be recovered. Such costs could force electricity rates up resulting in regulatory pushback. Merchant utilities relying heavily on coal or natural gas could incur higher compliance costs, and not all of these costs would necessarily be recovered through market pricing dynamics. Natural gas prices, which are volatile, can have an impact on the valuation of integrated names. Changes in the price of natural gas can affect the valuation of integrated electric utilities, both to the upside or to the downside. Such volatility appears inherent to the sector. Increases in cost of fuel can squeeze merchant margins. Coal, uranium, and natural gas are some of the fuel resources that competitive businesses rely on. Increases in the cost of these commodities, without offsetting power prices increases, can adversely affect profit margins. 13

14 Boston 100 Federal Street, 29 th Floor Boston, MA Houston Nine Greenway Plaza, Suite 2050 Houston, TX Metropolitan Washington, D.C. Headquarters 1001 Nineteenth Street North, Suite Arlington, VA F. Irvine (Los Angeles) Von Karman Avenue, Suite 950 Irvine, CA NOTE: Not all services are available from all offices. New York 299 Park Avenue, 7th Floor New York, NY San Francisco 1 Embarcadero Center, Suite 2140 San Francisco, CA