TODAY’S STUDY: OVER THE NATURAL GAS BRIDGE TO THE NEW ENERGY ERA

Natural Gas and Renewables: The Coal to Gas and Renewables Switch is on!
October 2011 (Deutsche Bank Climate Change Advisors)

Executive Summary

Natural Gas and Renewables Thesis – Share of Electricity Generation will Increase
In late 2010, DBCCA published an analysis concluding that (1) natural gas and renewable energy can play complementary roles in displacing coal-fired generation and lowering greenhouse gases (GHGs) emissions from the US electricity sector through 2030; and (2) at present a gas and renewables combination represents the most logical, politically acceptable, and economically feasible low-carbon energy pathway for the United States. On the supply side, the shale gas revolution remains front and center of this energy transition and continues to gather momentum.

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Evidence that the Thesis is Occurring

Since we last published, data shows that there has been:

• An increase of 2 percentage points in share of the US electricity mix coming from renewables (chiefly wind) from 2009 to mid-2011.

• If we adjust for the substantial short-run burst in generation from hydropower during this period (due to melting of an unusually large snowpack in the Pacific Northwest), then we believe the ongoing share of natural gas generation in the US electricity mix is also up by roughly 2 percentage points.

• Last year we forecast 60 GW of coal retirements by 2020 and another 92 GW between 2020 and 2030. We are maintaining our capacity replacement model and leaving the forecast unchanged. Since then, there has been a wave of analysis from the likes of the Edison Electric Institute (EEI) and IHS CERA (among others) analyzing the aggregate image of EPA regulations on coal retirements. Among studies that have been published in the last six months, coal retirements projected between 2010 and 2020 range between 35 GW on the low side to 101 GW on the high side…

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What’s New Compared to Our November 2010 Report?

This report takes a more granular and shorter-term view, assessing the immediate and nearer term market fundamentals and investment consequences of our long-term thesis including a greater focus on the environmental issues associated with natural gas and a revised capacity addition/retirement forecast. In brief,

• We see more needed scrutiny on the environmental issues associated with shale gas and scope for clear improvement in environmental performance and practices over the next 18 months, which we view as likely.

• We also calculate the source-to-use greenhouse gas emissions (GHGs) from natural gas - even when produced from shales - to be 47% below the source-to-use GHG emissions from coal…

• Finally, our long term forecast now calls for an even larger role for gas and renewables and a smaller contribution for nuclear power from 2020-2030 due to a sharp change in sentiment and changes in fundamentals in 1H11 stemming from the Fukushima disaster, which have recast nuclear energy as more costly and risky.

Nuclear Now Less Likely

Nuclear energy—never a big option in our US model—is even less of a pathway option going forward. Like renewable energy—nuclear energy requires significant subsidies to compete in energy markets. The knock-on impact resulting from the tragic events in Japan and the Fukushima disaster—which triggered a fast start 90 day review of the US nuclear fleet, some project cancellations and greater regulatory scrutiny which will almost certainly extend the timeline for capacity additions through 2020 and beyond—will be exacerbated by the stark contrast in new build costs for nuclear energy versus other sources. In August 2011 the Nuclear Regulatory Commission (NRC) shared the findings of its 90 day study with Congress. Overall, the Task Force found that continued operation and continued licensing activities do not pose an imminent risk to human health and safety. The Task Force, however, also proposed a number of regulatory and permitting modifications to improve nuclear energy’s risk profile, which will be an added cost. Accordingly, we have adjusted our long-term supply/demand model and see more limited growth in terms of capacity additions and larger plant retirements post 2020, owing to fewer 20-year life extensions and the impact of the cooling tower regulation by both the EPA and state regulators. Natural gas and renewables, as opposed to coal, fill the void from our reduction in nuclear energy growth.

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Gas Environmental Issues Under Scrutiny, but Manageable with Improved Industry Practices

We acknowledged in 2010 that there could be environmental challenges with natural gas—both for waste water disposal from extraction and lifecycle GHG emissions—without the implementation of best practices and improvements in regulatory oversight. But we believed then and continue to believe today that the challenges are manageable. In the interim, year-to-date through 2011, there has been heightened focused across all fronts on the environmental issues associated with gas and it appears as if the issues are now getting the full attention that they deserve from multiple stakeholders—from the President to producers to environmental advocates. For our part, we recently conducted a rigorous top-down life-cycle analysis (LCA) of natural gas versus coal generation applying the very latest (April 2011) upstream emission factors for natural gas extraction and conclude that from source to use electricity generated from natural gas is 47% cleaner than coal. (Please see: Comparing Life-Cycle Greenhouse Gas Emissions from Natural Gas and Coal, DBCCA, August 2011)…

Economics and Jobs

Our natural gas and renewables thesis is rooted in economics. And here, both the levelized cost of energy (LCOE) and total cash cost of electricity generated from gas and renewables compared to other energy sources, has improved even more over the past six months. Spot natural gas prices have remained stable, although the longer dated 2020 forwards have increased in response to Fukushima and expectations of an eventual increase for natural gas demand as coal-fired capacity is retired. Nevertheless, the overnight $/kW installed capacity prices for gas have remained stable. Meanwhile, solar and wind capacity prices have contracted significantly since year-end 2010 due to oversupply and improved learning curves. Accordingly, natural gas and renewables saw the largest capacity additions in the power sector in 2010, according to the Energy Information Administration (EIA), a trend we expect to continue.

Our companion paper to this research update, Repowering America: Creating Jobs (DBCCA, October 2011), looks at the job implications of our power market forecasts.4 We expect around 7.9 million net new job years to be created by 2030, leading to almost 500,000 net new jobs in place in 2030 as compared with 2010…

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Policy

Summary

• Policy is important to our power market thesis. For renewables while LCOE costs are higher than fossil fuels today they are declining rapidly—particularly true for solar PV—this is well understood and we revisit the key drivers. Federal renewable energy policy in the US looks set to remain volatile in the short term given political considerations. And since we last wrote the short term environment and outlook for renewables has if anything become tougher and more difficult. State and local programs, mandates and incentives can still remain supportive, particular in states with binding penalties for noncompliance with renewable portfolio targets.

• For natural gas-fired power generation the key question is the cost comparison to coal. Here, there are two elements of policy in play: 1) regulating health-related general pollutants; and 2) regulating CO2. The key role in 1) is the EPA and this can significantly impact coal costs and we expect to proceed over time, while the key to 2) is either Congressional legislation or EPA regulation—the current driver—and represents a key potential cost that is likely to influence power markets since the investment decision of dealing with general pollutants cannot be made without also factoring in the potential costs for carbon regulation.

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• Currently, there has been Congressional pushback to delay the EPA’s implementation of GHG regulation and some coal generators have pushed back publicly at the aggressive timeline of EPA implementation of the HAPs. However, given that the EPA is acting under court order to enforce the Clean Air Act we don’t expect significant delay. As a practical matter, a delay in the EPA enforcing GHG regulation is not that relevant in investment decisions because the unit by unit decisions on coal retirements that power generators are making today incorporate the comprehensive impacts of all known and expected regulation.

• The EPA’s recently announced revisions to the Cross-State Air Pollution Rule (CSAPR) do little to undermine the economic logic of a coal-to-gas switch. The EPA has recently proposed to (1) increase the emission budgets for coal-fired plants in 10 states covered under the CSAPR; and (2) delay the January 1 2012 deadline for CSAPR compliance, deciding that companies will now have until 2H12 or 1H13 to demonstrate compliance. While perhaps modestly prolonging the economic competitiveness of a few coal-fired units, such changes leave intact the economic incentive for utilities to base investment decisions on forthcoming regulations, including for GHGs. The new CSARP regime thus does little to undermine the incentive for utilities to swap coal and coal assets for gas and gas assets.

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EPA Regulatory Action: An Important Fuel-Switch Driver, No Way Out for Coal-Generators

The state of policy needs to be addressed since it is a key regulatory driver for the electricity sector. The US electricity sector is in the early stages of a profound period of change and capital stock turnover driven by the enforcement of EPA regulation, which is now at a critical inflection point and is the driving factor influencing long-term asset investment decisions. The implementation of the policy will persist for the next 10 years and is at the heart of our core investment thesis. Coal-fired power generation is the dominant source of US electricity supply today, providing about 43% of total electricity as of 2Q11. Coal’s large share is because it has historically been the cheapest source of electricity because the US has massive domestic coal reserves, and the human health and environmental damages associated with coal have been under priced. The fundamentals of coal-fired generation units explains their resilience to both regulation and competitive pressures: although coal plants have high upfront capital costs, their variable generation costs have historically been very low due to cheap and abundant domestic coal supplies. However, the coal fleet is now aging, inefficient relative to alternatives such as natural gas and lacking in control equipment to meet EPA regulations. Finally, the environmental, health and safety aspects of coal generation are relatively high compared to other sources of energy as shown in Table 13 below.

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Failure of Waxman-Markey Cap-and-Trade in 2010 Has Divided Utility Industry
In 2010 when there was a possibility of comprehensive national climate change legislation, the utility industry reached a consensus around policy. Over the past six to twelve months, however, as it has become clear that the EPA will be the vehicle for regulating climate change – not a bill passed by Congress – the gloves have come off. Electric generators unsurprisingly are divided in how they are responding to the onset of EPA regulation. There has been ample saber rattling from the coal generators most impacted on the one hand arguing for more time to prepare for the EPA timeline while natural gas and nuclear generators with the most to gain believe that the impact of regulation is manageable. This is because there are major impacts in terms of winners and losers. Coal generators now face a “perfect storm” of federal and state regulatory and legislative action focused on hazardous air pollutants and GHGs from coal-fired power plants, which we expect can reduce coal’s share of electricity to 32% by 2020 and 22% by 2030, as coal-fired generation becomes less economic by our reasoning relative to natural gas-fired generation and renewables ramp up.

A series of court decisions that have been in the works for some time and large budget appropriations during the first two years of the Obama administration have given the EPA greater authority and a clear mandate to effectuate long overdue levels of regulatory restrictions on coal power plants under a compressed timeframe. Mercury and acid gases are part of the “hazardous air pollutant” (HAPs) regulations that will likely require what the EPA calls maximum available control technology (MACT) for all coal units. This particular regulation is the focal point of decision making for coal-generators since it cuts across the other regulations, too, and requires a unit by unit assessment. MACT sets required performance standards equal to the best 12% of operating plants. Broadly for mercury this will require about a 90% removal rate, although sub-categorizations could lower this number for some plants and raise it for others. Other upcoming regulations include (1) the Cross-State Air Pollution Rule (CSAPR) - formerly called the Clean Air Interstate Rule (CAIR) - which will limit emissions trading for sulfur dioxide emissions, (2) new rules on coal-combustion residuals such as ash disposal; (3) new rules on cooling water intake structures and (4) new source review permitting. For a more complete definition of the terms referenced in Exhibit 28 below please see the EPA’s Terms of Environment (www.epa.gov/OCEPAterms/).

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2011 is the key turning point on regulation and it is clear that those generators and suppliers most affected are trying their best to dig in their heels in what looks to be a losing battle. The issue most at stake is timing and an attempt to be given more time to comply, given the complexity of the alphabet soup of EPA regulations and the impact that they will have in the aggregate on long term investment decisions. Coal-fired generators have argued that meeting the 2014 deadline for HAP compliance is infeasible given the long lead times to procure the equipment and technology needed to retrofit coal plants and have been pushing for more time. On this score, the first half of 2011 marked a sharp increase in lobbying activity from coal-dominated utilities to more than 90 congressional offices in an effort to stall the implementation of EPA rules, according to Bloomberg News.33 Meanwhile, House subcommittee Chair Representative Ed Whitfield (R-KY) has promised to introduce a bill to delay the Utility MACT with support of large coal utilities such as American Electric Power (AEP). In addition, US Representative John Dingell (D-MI) has proposed extending the comment period from 60 to 120 days (through September 2011) to allow industry to respond to EPA’s proposed CSAPR regulations before final rule making occurs in November 2011.
In response to pressure from the Democratic representative, EPA did flex a bit and announced on June 21, 2011 a 30-day extension of the comment period for the proposed Utility MACT standard to allow the industry an extra month to respond.

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More recently, the EPA has proposed to (1) increase the emission budgets for coal-fired plants in 10 states covered under the CSAPR; and (2) delay the January 1 2012 deadline for CSAPR compliance, deciding that companies will now have until 2H12 or 1H13 to demonstrate compliance. Proposed changes to state emission budgets will affect roughly 2-3% of the 1,000 facilities covered under CSAPR (i.e. 20-30 plants); depending on the pollutant in question (e.g. SOx vs. NOx), the new larger emissions budgets allow 1-4% more emissions nationwide. While perhaps modestly prolonging the economic competitiveness of a few coal-fired units, such changes leave intact the economic incentive for utilities to base investment decisions on forthcoming regulations, including for GHGs. The new CSARP regime thus does little to undermine the incentive for utilities to swap coal and coal assets for gas and gas assets.

With respect to the EPA’s extended deadline for CSAPR compliance, we still expect the schedule for implementation of both the Utility MACT and CSAPR rules to largely follow the guidelines under the Clean Air Act (CAA) of three years, plus an additional year if needed. We do believe that if a utility should be unable to comply with EPA deadlines, EPA will allow additional discretion on a case-by-case basis to extend the process for a reasonable time, if extenuating circumstances provide justification. Both the one-year extension and any further discretion are decided at the local and state levels.

Deadlines for MACT and CSAPR compliance are unlikely to be severely pushed back because a delay of the Clean Air Act (CAA) which is governing EPA regulation requires a change in legislation or a declaration from the President that enforcement of regulation would jeopardize the nation’s national security—again not likely. Moreover, the CAA is very clear on statutory deadlines; compliance is required three years from publication of the final rules, although there may be some flexibility for an extra year extension on a case-by-case basis. Therefore, we remain unconvinced that industry and Congress will be able to change the EPA’s mandate during the comment period, seeking tweaks to EPA’s proposed regulation. Comments from industry would need to be very persuasive and heavily supported from data proving the EPA’s assumptions are wrong. Given the relatively short window for comment, we do not see this as an issue. With this fight likely ending, attention has now been turned to questions over job losses and higher electricity prices.

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The American Coalition for Clean Coal Electricity—an advocacy group supported by coal generators—released analysis on June 8, 2011 based on a study conducted by NERA Economic Consulting that showed that the combination of MACT and CSAPR would result in the closing of 48 GW of coal plants, an increase in electricity costs of ~$18 billion per year and a ~12% increase in average national electricity prices by 2016 with some coal regions seeing an increase of as much as ~24%.34 Building on the release of this report, American Electric Power (AEP) disclosed on June 8, 2011 that its preliminary plans for complying with EPA regulations would entail retiring 6,000 MW of coal-fired generation, upgrading or installing scrubbers on 10,100 MW, repurposing 1,070 of coal-generation to be natural-gas units and building 1,220 MW of new gas-fired generation. AEP stated that it would be able to comply with EPA regulation but cautioned that the result would be the loss of 600 power plant jobs and a “sudden increase in electricity rates and impacts on state economies will be significant at a time when people and states are still struggling.”35 AEP would clearly like to delay the implementation of EPA policy. However, given the momentum, we view this as unlikely.

The consequences of EPA regulation on jobs and electricity prices are important. However, our research runs contrary to AEP’s assertion. As we showed earlier, we see the potential for existing gas-fired generation to make up for as much as ~96% of the loss in coal-fired generation in the MISO and SERC regions that are most impacted by EPA regulation with very modest incremental infrastructure costs. The jobs issue, however, is more complicated. Because of their complexity, coal units require larger numbers of employees per MW than gas units. Therefore, on a comparable basis new gas units require fewer employees than a coal unit. But this is largely a distributional issue. When adding the net additions to renewables and gas jobs to the losses from shuttered coal facilities, we believe there is more than a one to one offset. Importantly, for the economy in aggregate the job creation benefits from shale gas are likely to eclipse any losses from coal retirements. The number of jobs per trillion cubic feet (TCF) of gas varies from state to state, but we estimate nationally is about 50,000 new jobs for every TCF of gas production. This number is roughly 3x the number of jobs from an equivalent amount of coal production.36 To put this into context, if we see US annual demand for natural gas increase to about 30 TCF over the next 20 years from 24 TCF today, this would equate to approximately 300,000 high paying jobs.

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Finally, we would note that we continue to think the market broadly underestimates the potential for significant reductions in electricity consumption due to demand side management and energy efficiency programs and the soup to nuts ramifications of the shale gas revolution, which is likely to put a lid on natural gas prices and therefore power prices…

When all is said and done the net impact to the consumer and to the economy of coal retirements on electricity prices and jobs is not likely to be as dire as the coal industry would have one believe. Lew Hay, Chairman and CEO of Next Era Energy, a leading natural-gas and renewables power generator has a similar view as illustrated by comments on the company’s first quarter 2011 earnings call. “I don’t believe that replacing 50-year old fossil plants with new, more efficient units will be the train wreck we have been hearing so much about. Nor do I believe that putting pollution controls on many of the remaining plants is all that terrible. As an aside, it is interesting to note that two-thirds of our nation’s coal fleet is without meaningful pollution controls. While there is no free lunch, the cost of this upgrade to that nation’s generation fleet is likely to be far less than the costliest predictions.”