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Carbon Market Analyst

Carbon Exposure: Winners and Losers in a US Carbon Market

TO THE POINT CONTENT

UPCOMING REPORTS

POINT CARBON RESEARCH All rights reserved © 2009 Point Carbon

RESEARCH

North America

2 Executive summary

3 Introduction

3 Setting the scene

5 Carbon flows

9 Carbon costs

13 Winners and losers

15 Conclusion

16 Contacts

• US emission and price forecast

• Global supply-demand towards

2020

• International offset supply and price

forecast post-2012

Power and oil companies’ carbon exposure depends not only on emissions and free allowances, but also on the amount of ‘pass-through’ of the carbon cost to consumers.

Oil companies’ carbon exposure is very limited because they will be able to recover most of their costs through a 5 percent increase in gas prices at the pump. The companies with the highest exposure are Exxon and Shell but only by around 0.5 percent of their operating incomes.

Coal-based power companies in regulated markets like Southern, AEP and Duke are most exposed to carbon emission caps. Their exposure could reach 12 percent of their operating income.

Merchant generators with low-emitting fleets stand to benefit from carbon caps. Exelon could increase its operating income by 36 percent.

November 2, 2009

Disclaimer

The data provided in this report were prepared by Point Carbon’s Trading Analytics and Research division. Publications of Point Carbon’s Trading Analytics and Research division are provided for informational purposes only. Prices are indicative and Point Carbon does not offer to buy or sell or solicit offers to buy or sell any financial instrument or offer recommendations to purchase, hold or sell any commodity or make any other investment decision. Other than disclosures relating to Point Carbon, the information contained in this publication has been obtained from sources that Point Carbon believes to be reliable, but no representation or warranty, express or implied, is made as to the accuracy or completeness of this information. The opinions and views expressed in this publication are those of Point Carbon and are subject to change without notice, and Point Carbon has no obligation to update either the opinions or the information contained in this publication.

Point Carbon’s Trading Analytics and Research division receives compensation for its reports. Point Carbon’s Trading Analytics and Research division reports are published on a subscription basis and are not issued at the request of any client of Point Carbon.

Carbon Market Analyst North America

2 All rights reserved © 2009 Point Carbon

CMA November 2, 2009

This report analyzes how the proposed US cap-and-trade market will impact the financial health of some of the largest emitters that will be covered by the program. A cap-and-trade program creates complex flows of allowances and recovered costs, and it is important for stakeholders and investors to understand what this will mean for the valuation of these companies.

Our analysis focuses on the largest emitters in the two largest sectors covered by the cap, power and oil, which represent cumulatively about 40 percent of covered emissions in the US market. We quantify carbon costs and revenues under the climate bill before the US Senate.

At the company level, the carbon exposure depends on the expected costs of carbon and the potential revenue flows associated with carbon regulation. Costs are based on the amount of allowances a company needs to cover its emissions and the free allowances it receive under the cap-and-trade program. Revenues depend on the carbon pass-through – how much of the cost of carbon is passed on to final consumers through an increase in retail sales. By comparing the final costs of carbon to companies’ financial indicators, we show which companies are the most and least exposed to carbon.

Power companies with a fleet of low-emitting plants stand to be the winners of the program, while coal generators may not be able to recover all their costs.

The companies with the largest exposure under the Kerry-Boxer bill are Southern Co, AEP, and Duke. Their operating income is most sensitive to the cost of carbon, respectively estimated at 12, 11, and 5 percent.

For others, carbon regulations will have a positive impact on their balance sheets. The final cost of carbon for Exelon is a net gain of over 36 percent of its operating income. Other companies that could experience a positive effect on operating incomes include FirstEnergy (19 percent), Edison (11 percent), NRG (11 percent) and PG&E (eight percent).

Most of the power companies in our study have an operating income exposure close to zero. These companies, like Progress and Ameren, come out slightly on the winning side in the first years of the program because of the coal merchant allocation, but those free allowances are quickly phased down and the gains are unlikely to last long.

Oil companies will recover most if not all of the carbon costs from combustion emissions but are exposed on their refining emissions because refineries abroad do not face the same compliance costs.

Cap-and-trade programs create incentives to invest in low-carbon technologies and penalize financially the high-emitting technologies. As the market matures, companies will be able to mitigate their exposure through internal reductions and offset investments.

Executive summary

Figure ES-1: Winners and losers in a US carbon market

First Energy

PG&E

Xcel

ExxonMobil

Shell

ChevronBP

ConocoPhillips

Progress

NRG

Dominion

Duke

Edison

Ameren

MidAmerican

Southern

AEP

-5

-3

-1

1

3

5

-38 -32 -26 -20 -14 -8 -2 4 10 16

Opera

ting in

com

e e

xposu

re (

%)

Exelon

-9

-7

Revenue exposure (%)




IntroductionThe largest emitter of greenhouse gases (GHGs) in the US is an oil company. Its total annual GHG emissions account for over six percent of total emissions covered by the proposed cap-and-trade program. As the current proposal in Congress stands, this oil company would receive very few free allowances to cover its emissions - less than one percent of its total annual GHG output. Given a $15 price of carbon, the oil company will need to pay $5.9 billion annually to purchase the carbon allowances it needs for compliance, amounting to eight percent of the oil company’s operating income.

This example illustrates why companies likely to be regulated in a US cap-and-trade program to account for the cost of carbon on their financial balance sheets as the US moves closer to implementing a national carbon cap. While many of these emitters prepare to pay for their greenhouse gas emissions for the first time, it is important for stakeholders and investors to understand what that will mean for the valuation of their companies.

The Securities and Exchange Commission (SEC) requires companies to reveal climatic threats to their bottom line, but according to the report, “Reclaiming Transparency in a Changing Climate: Trends in Climate Risk Disclosure by the S&P 500 from 1995 to the Present” (Ceres Coalition, Environmental Defense Fund, and Center for Energy and Environmental Security, 2009), over 75 percent of Standard & Poor (S&P)’s 500 companies failed to

mention climate change in their annual reports. This highlights the need for the SEC to protect investors from the inadequacies in corporate disclosure concerning the risks and opportunities related to climate change.

In this issue of Carbon Market Analyst, we analyze the carbon exposure of key companies that will be regulated under the proposed US cap-and-trade program. We define carbon exposure as the extent to which a company’s value creation is affected by the cost of emitting GHGs, called its carbon cost.

We attempt to answer two main questions. First, who are the main players in a US carbon market and what are their expected carbon cost and carbon revenue flows? Second, which sectors and which companies display the highest carbon exposure

in the proposed cap-and-trade program?

We first present an overview of emissions by sector and by company, focusing on the power and oil sectors. We then quantify their carbon costs and revenues, estimating volumes and cash flows by sector. Finally, we compare across sectors the capacity of these large emitters to shoulder – or take advantage of – the upcoming carbon regulation.

Setting the scene Sectoral dynamics

The proposed Senate climate bill caps most emissions from the power, transportation, industrial, residential, and commercial sectors. In 2005, the power sector and the oil and natural gas sector together accounted for almost three quarters of the emissions that would be covered under the Senate bill’s cap (see Figure 1). Emissions from the industrial sector amounted to one

Figure 1: Emissions from regulated sectors (6 billion metric tons CO2e)

Power (2,427mt) 40%

Transportation (2,035mt) 33%

Industry (1,177mt) 19%

Residential and Commercial Heat (459mt)

8%

Data source: EPA June 2009 and Point Carbon

We identify compa-nies with the high-

est carbon exposure

Companies need to account for the cost of carbon on their

financial balance sheets




Figure 2a and b : Largest emitters in the oil and power sectorsThe oil sector (left) is rather concentrated, while the power sector (right) includes over three thousand entities.

Table 1: Company-level emissions

Company Estimated US emissions (Mt CO2/year)

Percent of sector emissions Percent of total US covered emissions

ExxonMobil 397 15.8% 6.5%

Chevron 360 14.3% 5.9%

ConocoPhillips 327 13.0% 5.4%

BP 240 9.6% 3.9%

Royal Dutch Shell 205 8.1% 3.4%

Oil & Natural Gas Companies 60.8% 25.1%

AEP 156 6.4% 2.6%

Southern 149 6.2% 2.4%

Duke 101 4.2% 1.7%

Ameren 68 2.8% 1.1%

MidAmerican 65 2.7% 1.1%

NRG 61 2.5% 1.0%

Dominion 60 2.5% 1.0%

Xcel 56 2.3% 0.9%

FirstEnergy 53 2.2% 0.9%

Progress 53 2.2% 0.9%

Edison 53 2.2% 0.9%

Exelon 10 0.4% 0.2%

PG&E 2 0.1% < 0.1%

Power Companies 36.6% 14.6%

ExxonMobil, 16%

Chevron, 14%

ConocoPhillips, 13%

BP, 10%Royal Dutch Shell, 8%

Other, 39%

AEP, 6.4%

Southern, 6.2%

Duke, 4.2%

Ameren, 2.8%

MidAmerican, 2.7%

NRG, 2.5%

Dominion, 2.5%

Xcel, 2.3%

FirstEnergy, 2.2%Edison, 2.2%

Progress, 2.2%

Other, 62.9%




fifth of covered emissions, with the residential and commercial (heat) sectors making up the last eight percent.

Largest US emitters

This study focuses on the largest emitters in the two largest sectors, power and oil. Together, these emitters are responsible for close to 40 percent of covered emissions under the proposed cap-and-trade system.

At the corporate level, the top five emitters in the US are oil companies: ExxonMobil, Chevron, ConocoPhillips, BP and Royal Dutch Shell (see Table 1). They emit a cumulative 60 percent of the oil (‘transportation’) sector’s emissions and are responsible for 25 percent of the emissions a US carbon market would create. Exxon alone accounts for 6.5 percent of the markets’ emissions.

We analyze 11 of the largest emitters in the power sector, which together represent almost 37 percent of that sector’s emissions and 15 percent of total covered emissions. Individual power companies are responsible for a much smaller amount of emissions than oil companies. The largest-emitting power company, American Electric Power (AEP) emits less than half of what Exxon emits.

Aside from the top 11 power sector emitters, we also analyze two power companies with low emission levels, Pacific Gas and Electric (PG&E) and Exelon, in order to compare the relative impacts of carbon regulation among firms with comparable generation and sales but different emission rates.

Carbon flows Definitions

To determine the impact of carbon legislation on companies’ financials, we look at direct carbon costs and revenues.

Gross carbon costs are based on the amount of allowances a company needs to surrender for compliance – their emissions multiplied by the price of allowances.

The net carbon cost is the amount of allowances companies need to purchase - the difference between their total emissions and the number

Sectoral emissions were estimated based on 2005 US emissions, the reference year in the Kerry-Boxer bill. Company-level emissions are 2007 data except for a few (listed below). 2005 and 2007 US emissions were close enough (7.1Gt in 2005, 7.05Gt in 2007) to justify comparing 2007 company-level emissions to 2005 sector emissions.

Company-level emission data for all but a few companies was obtained courtesy of the Carbon Disclosure Project (CDP), an independent not-for-profit organization holding the largest database of primary corporate climate change information in the world. Approximately 50 percent of S&P 500 companies currently disclose to the CDP direct greenhouse gas emissions in accordance with the World Business Council for Sustainable Development and the World Resource Institute’s GHG Protocol. Responding to the CDP or other emission reporting databases provides a high level of visibility and accountability to all stakeholders and investors in companies.

Some of these companies only report global or North American emissions. We estimated US emissions applying the ratio of their US to global (or North American) production to their emissions. Specifically, we used this method for three of the oil companies’ refinery emissions: Exxon, Conoco, and Chevron. Combustion emissions were calculated using product sales multiplied by Energy Information Agency (EIA) emission conversion coefficients. In the case of BP, product sales were based on the ratio of US sales to world sales across each product.

Four power companies did not report their emissions through the CDP: Southern Co, MidAmerican, FirstEnergy and Edison International. For these companies, we used 2006 data from the report “Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States - 2006.” The report was a collaborative effort by Ceres, the Natural Resources Defense Council, and Public Service Enterprise Group.

Textbox 1: Emission data sources

of free allowances they are allocated under the legislation.

Carbon revenues depend on the carbon pass-through– how much of the cost of carbon is passed on to final consumers through an increase in retail prices. We estimate the level of pass-through (‘recovered costs’) for each sector and multiply by sales for each company.

The top five US emitters are oil com-

panies

The net carbon cost is the difference between emissions

and free allowances




The final cost of carbon is the difference between the net carbon costs and the carbon revenues. It is our best estimate of the final impact carbon will have on each company once all the carbon flows have been taken into account.

Rather than try to forecast companies’ emissions several years in the future, we looked at what would happen if the proposed cap-and-trade program started today. We use as a proxy for the price of carbon $15 per ton, which is our most recent forecast averaged over the 2012-2019 period. We apply for each company the allocation formula and allowance availability in the first year it would be regulated under the program – 2012 for power and transportation, and 2014 for industries. The purpose is not to obtain a precise estimate of individual firms’ carbon exposure, but rather to establish orders of magnitude for the carbon flows at stake. We determine the relative exposure of the companies across sectors, identifying potential winners and losers.

Carbon flows in the oil sector

Under the proposed Senate legislation, oil companies are responsible for both their refining emissions, classified as “industrial emissions” (phased-in in 2014), and for “downstream” transportation emissions, which result from the combustion of the gasoline product they sell, starting in 2012.

The refining emissions are partly covered. The allocation plan in the Kerry-Boxer bill allocates 0.75

percent of allowances to large domestic refiners, such as the ones in this analysis, whereas mid-sized refiners receive 0.5 percent and small refiners one percent.

The allowances are distributed based on each company’s percentage of the US refinery sector’s total output through 2026. Oil companies do not receive any allowances for the transportation emissions, which make up over 90 percent of their compliance obligation.

We expect that oil companies will largely be able to recover their costs for downstream emissions as they pass through the cost of carbon to the end-consumers. A $15 price of carbon translates to a 13 cents per gallon increase at the pump (5 percent of current gas prices), an amount negligible compared to price changes induced by the volatility on oil markets. Oil prices will increase across the board because imports of refined oil are also subject to the compliance obligation. The final cost of carbon for oil companies is therefore limited essentially to a fraction of the refining costs.

Figure 3 is a simplified representation of the carbon allowances and cash flows in the oil (transportation) sector.

Figure 3: Carbon allowances and cash flows in the oil sectorOil companies receive a small amount of free allowances going to their refiners. They need to purchase most allowances they need for compliance from the allowance and offset market. This raises the costs for oil companies, which will be passed on to consumers as higher gas prices. The increase in revenue from higher gas prices represents the carbon revenue, or recovered costs, for oil companies.

Oil company

Final consumers

Government

Allowance & offsets market

Allowances surrendered for compliance

Free allocation to refiners

Recovered costs from higher prices at the pump

Allowances/offsets

Dollars

Companies recover part of the costs by passing them on to

final consumers

A $15 price of car-bon translates to a 13 cents per gallon

increase at the pump




Carbon flows in the power sector

Emissions from the power sector are covered at the power plant level – companies operating fossil fuel-fired generating units must surrender allowances to cover their emissions from those plants.

Under the Kerry-Boxer program, a large portion of free allowances goes to the power sector, but not to the electricity generators (see Figure 4). Rather, allowances are allocated to electricity distributors: local electric distribution companies (LDCs) are allocated 27.5 percent of the total annual US allowance budget for free and must use the proceeds from these allowances “for the benefit of electricity consumers.” LDCs will receive the allowances based half on the electricity they deliver and half on its associated emissions.

A small portion of allowances is allocated directly to generators, including merchant coal generators and long-term contract holders. Merchant coal generators are eligible for free allocation based on their emissions, but this allocation may not exceed ten percent of the utility sector allowance budget.

Contract holders under the Public Utility Regulatory Policies Act (PURPA) are also eligible for allocation based on emissions but their allocation may not exceed 4.3 percent of the utility sector allowance budget. It is impossible to model exactly how these allowances will be allocated in reality without knowing the content of these private contracts, so we have simply combined the contract set aside allowances with the rest of

Figure 4: Carbon allowance and cash flows in the power sector.

Generator

Final consumers

Government

Allowance & offset markets

Allowances surrendered for compliance

Free allocation to coal merchant generators

Recovered costs from higher retail rates

Distributor

Free allocation to LDCs

Electricity holding company

Value of free allowances passed on to consumers as rebates

Allowances/offsets

Dollars

Higher wholesale

rates

Internal allowance

transaction

A large portion of free allowances goes to the power sector,

but not to generators The impact of carbon allowance prices on electricity prices varies according to the fuel mix used to generate electricity. Coal emits close to 1 ton of CO2 per MWh of electricity, while modern natural gas combined cycle plants emit approximately 0.4 tons per MWh. Nuclear, hydro and renewable do not emit CO2. The impact on wholesale prices further depends on the state of market regulation. In deregulated markets (PJM, NYISO, NEPOOL, California, Texas), rates are set via marginal cost pricing. In regulated markets they are set by the average cost of the plants in the region. For more details on this topic please refer to our report The Power of Carbon, published July 2008.

How much of the cost will be passed on to final consumers depends on how the electricity market is regulated. In deregulated markets, the costs should be fully passed on to consumers. In regulated markets, the extent to which utilities can ‘pass through’ the carbon costs to retail consumers is determined by regulators. Provided that the cost of procuring allowances qualifies as an allowable cost in the view of the Public Utilities Commissions, we can expect to see 100 percent pass-through in regulated markets as well.

Based of these differing market regulations, and to reflect the fuel mix and the associated emission rate variations by region, we modeled the differentiated impact of carbon by state (regulated markets) or market (deregulated markets), see Figure 5.

Textbox 2: Carbon and power prices




Figure 5: Impact of carbon on electricity prices

5 – 8 $/MWh 13 – 17 $/MWh

10 – 13 $/MWh

8 – 10 $/MWh

< 5 $/MWh

the allowances going to LDCs.

Figure 4 represents the allowance and cash flows in the power sectors. On the generation side, power generators have to purchase most of the allowances they need for compliance – aside from the small portion coal merchant generators receive. This raises the cost of generating electricity, which is reflected in higher wholesale electricity rates (see Textbox 2). These increased revenues constitute the carbon revenue, or recovered costs, for generators.

On the distribution side, LDCs are merely a redistribution agent for the federal government. LDCs receive free allowances, which they sell back either to the generation branch of their holding company or on the open carbon market. The

proceeds from the sales are then redistributed to end-consumers, directly through consumer rebates or indirectly through investments in energy efficiency programs – but not through lower rates, as the flows must be kept separate according to the Kerry-Boxer bill. In parallel, LDCs will also pass on most of the increase in wholesale power prices onto end-consumers through higher retail rates (see Textbox 2).

Although the compliance entity and the recipient of the allowances are two separate companies, many of

them belong to the same larger holding company. Hence we expect most allowance transactions to take place internally, between the generation and the distribution sides of the same firm. The transactions will likely be registered as over-the-counter transactions, and will have to be registered in the Federal carbon allowance registry. Overall, the carbon costs and revenues should cancel each other out completely on the distribution side, while generators are subject to gains or losses depending on the composition of their fleet and the markets in which they operate.

As a side note, power generators in large holding companies have a practical advantage over the other sectors or fully independent power generators. Their ability to procure allowances internally means they

The impact of carbon on electricity prices varies by power mar-

ket or region




Allocation

We estimate allocation by applying the formulas laid out in the Kerry-Boxer bill. The allocation to the power sector is particularly difficult to estimate because it is based on a mix of electricity sales and emissions associated with these sales – as opposed to emissions from the generation. For load serving entities in regulated markets (Southern, Duke, AEP, etc.) we used their average emission rate multiplied by their sales in MWh (EIA data).

For power companies in deregulated markets (NRG, FirstEnergy, Exelon, etc.), emissions from the electricity sold is impossible to quantify from publicly available data. We use a rough estimate based on the LDCs’ share of state market sales multiplied by the state’s average emission rate. This method has two significant limitations: 1) it ignores differences among utilities’ emission rates within a state and 2) it does not take into account power imports and exports between states. In spite of these limitations, this method allows us to get a rough estimate of the allocation to every private and public LDC in the country.

For the allocation to merchant coal generators, we collected emissions data (eGRID) for qualifying plants (EIA 860) and aggregated emissions by company. We then estimated the amount of allowances based on half of these emissions and pro-rated by the ratio of available allowances to emissions from merchant coal generators.

The allocation to the oil sector is based on total US refinery output. For each company’s percentage of refinery output, we used the ratio of its US refinery capacity to total US refinery capacity. The projection of capacity to output remains relatively constant, although differences in efficiency among companies could result in slightly different allocations.

Recovered costs:

We estimate the revenue increase for power companies by multiplying their generation by state by our estimated increase in wholesale rates. These increases are based on the average emission rate for states with regulated electricity markets (EIA data) and marginal emission rates for deregulated markets (ISO data). We assume that in both cases the cost of carbon is entirely passed on to final consumers.

We estimated plant-level generation by company from EIA forms 906 and 920 and plant ownership from form 860, 2007 data. We benchmarked our generation data with the Ceres report on the 100 largest emitters in the US (2006 data) and adjusted total generation where necessary.

Because utility territories and power markets differ across state lines, this method simplifies reality and is bound by the same limitations as our allocation methodology.

Similarly, we assume 100 percent of the costs of allowances covering combustion emissions are passed through to consumers via higher gasoline prices in the oil sector. However, we assume that the costs of the allowances covering refining emissions are not reflected in final gas prices, as these would encroach on the competitiveness of domestic refiners against imported refined oil.

While these numbers are not exact by any means, we believe they represent the best publicly available data and our best effort to quantify carbon costs and revenues at the company level.

Textbox 3: Allocation and recovered costs methodology

will likely be sheltered from possible price volatility on the open market and will not be vulnerable to lags in allowances reaching the market. (See our report Everything you need to know about Waxman-Markey, published in September 2009, for more analysis of market dynamics).

Carbon costs How do these costs and revenues translate at the company level? We estimate the quantity of free allowances allocated to each company in our study, and compare to their emission levels. To get an indicative cost of carbon, we

multiply a company’s shortage of allowances in the first year of the program by our forecasted prices of carbon allowances in the proposed US market, $15 per ton of CO2 on average over the 2012-2019 period.

We estimate carbon revenues for power sector emitters by quantifying




the increased revenue from increased retail electricity rates. For oil companies, increased revenues are earned from higher prices at the pump (see Textbox 3 for details on our data source and methodology).

Carbon costs in the oil sector

The major oil companies have logically the highest gross costs for carbon. Exxon tops the list at $5.9 billion, while Shell has the lowest gross carbon cost of the oil companies covered in this analysis, at $3.1 billion.

The aggregate free allocation to these oil companies represents less than half of one percent of the total allowances in the market in the first year they are covered. Each oil company has relative allowance shortages of over 99 percent, because its refinery emissions are dwarfed by transportation emissions. This means that the free allocation has a negligible impact on each oil company’s net cost of carbon, which is what it has to pay after free allocation.

Any discrepancy be-tween carbon costs and pass through

could have large conse-quences

The oil companies have global business operations, and are therefore also subject to compliance in the European Union Emission Trading System (EU ETS).

Net carbon costs in the EU are comparatively smaller, mainly because the oil companies receive a greater proportion of free allowances in the EU ETS and because transportation emissions are not covered in that program. Based on 2008-2012 average emissions, and using Point Carbon’s most recent price forecast for EUAs and CERs, we find that Exxon has a net cost of carbon of $140 million and Shell of $63 million per year.

Some of the major oil companies are actually long allowances in the EU program, meaning they receive more free allowances than they need to cover their actual EU emissions. This leads to another source of potential revenue for these companies, as is seen with BP, Conoco, and Chevron. In our estimate, BP could receive extra allowances worth $112 million, Conoco $10 million, and Chevron $8 million per year.

However, this dynamics will change as the EU moves away from free allocation to refineries in Phase 3 of the EU ETS, and we expect the cost of carbon in the EU ETS to grow significantly from Phase 2 levels.

For more details on the costs of carbon in the EU ETS please refer to our report Carbon Exposure EU ETS, published January 2009. Because of the difference in methodology in our two reports we do not aggregate the cost of carbon in the EU ETS to our US estimates.

Textbox 4: Carbon costs in the EU ETS

Table 2: The cost of carbon in the oil sectorAll volumes are in million metric tons of CO2e (mt) per year, all costs are in million USD.

Company Estimated US Emissions (refinery)

Estimated US Emissions

(combustion)

Estimated Allocation

Absolute Shortage

Relative Shortage

Gross cost

Net cost Carbon Revenues

Final Cost of Carbon

ExxonMobil 22 375 3.1 393 99.2% $5 948 $5 901 $5 624 $277

Chevron 18 342 1.6 358 99.6% $5 397 $5 373 $5 126 $247

ConocoPhillips 22 305 3.0 324 99.1% $4 909 $4 864 $4 578 $285

BP 26 214 2.5 238 99.0% $3 602 $3 565 $3 210 $355

Royal Dutch Shell 19 185 0.7 204 99.6% $3 068 $3 057 $2 780 $276

The recovered costs that oil companies will receive by passing on costs to consumers at the pump are also very large. Again, Exxon has the potential to receive the most carbon revenues at $5.6 billion. These recovered costs are proportional to the company’s combustion emissions. Because of the large amounts, any small discrepancy or

time lag between the carbon costs and the actual pass-through could have large financial consequences for oil companies.

After carbon revenues from increased retail gas prices are accounted for, BP has the greatest final cost of carbon at $355 million and ConocoPhillips has the second highest final cost of




Table 3: The cost of carbon in the power sectorAll volumes are in million metric tons of CO2e (mt) per year, all costs are in million USD.

Company Estimated US Emis-

sions

Estimated Allocation

(LDCs)

Estimated Al-location

(Merchant Coal)

Absolute Shortage

Relative Shortage

Gross cost

Net cost Carbon Revenues

Final Cost of Carbon

AEP 156 70 0 156 100% $2 345 $2 345 $2 093 $252

Southern 149 74 0 149 100% $2 240 $2 240 $1 846 $393

Duke 101 55 0 101 100% $1 512 $1 512 $1 383 $129

Ameren 68 33 7 61 89% $1 023 $912 $970 $(58)

MidAmerican 65 38 0 65 100% $982 $982 $1 050 $(69)

NRG 61 27 22 39 63% $915 $579 $743 $(164)

Dominion 60 31 6 54 90% $895 $806 $1 016 $(210)

Xcel 56 43 0 56 100% $847 $847 $874 $(27)

FirstEnergy 53 41 19 34 64% $799 $509 $1 004 $(494)

Progress 53 34 6 47 89% $796 $707 $771 $(64)

Edison 53 20 17 35 67% $788 $531 $810 $(279)

Exelon 10 5 2 9 84% $154 $129 $1 824 $(1 695)

PG&E 2 5 0 2 100% $29 $29 $199 $(170)

carbon, at $285 million. Chevron has the lowest final cost of carbon at $247 million. These variations in final costs are driven by differences in the ratio of local refining to total US sales and the efficiency of their US refining operations.

Given the global scope of the oil companies business operations, we also take a look at their costs of compliance within the European Union Emission Trading System (see Textbox 4).

Carbon costs in the power sector

All of the power companies have lower gross costs of carbon than the oil companies. As should be expected, AEP has the highest gross cost of carbon at $2.3 billion and Edison International has the lowest (of the 11 big emitters included in this study) at $788 million. Comparatively,

Figure 6 : The cost of carbon: power and oil Final cost of carbon for the main emitters in the power and oil sectors. Positive numbers indicate a positive cost, i.e. net loss, and negative numbers represent negative costs, i.e. net revenue.

-$2,000

-$1,500

-$1,000

-$500

$0

$500

Mill

ion

s




PG&E has a gross cost of carbon of only $29 million.

We subtract the allocation to merchant coal generators from the companies’ total emissions to find their net cost of carbon. The companies that receive the highest merchant coal allocation are NRG, FirstEnergy, Edison, and Ameren. Hence, their net carbon costs are reduced, whereas the other power companies that do not receive merchant coal allocation have net costs equal to their gross costs. Of the big emitters, FirstEnergy has the lowest net cost of carbon at $509 million, followed by NRG at $579.

The ability of power generators to pass on the cost of carbon to consumers varies by company and power market. A company with a low-carbon fleet (nuclear, renewable or even natural gas) in a market where prices are set at the margin by electricity from coal-fired generation will potentially recover more than its actual costs because it will benefit from the larger price increase without having to pay for as many allowances. Conversely, a company with many coal power plants in a market where prices are set by natural gas on the margin would not recover all its carbon costs through the price increases – an issue addressed in part by the free allocation to merchant coal generators.

Based on our estimates, AEP is able to recover the greatest amount of cost - over $2.0 billion. This represents almost 90 percent of the company’s net cost. Southern has the ability to recover 82 percent of its net cost, which is equal to $1.8 billion, and Duke could recover over 90 percent of its net cost at $1.4 billion. The other

The two indicators for expressing the carbon exposure are ratios that reveal a firm’s revenue exposure and operating income exposure. The final cost of carbon (incurred costs) is the nominator in both. We have calculated the denominators in each indicator as follows:

1. Revenue Exposure: the final cost of carbon divided by the company’s revenue.

2. Operating Income Exposure: the final cost of carbon divided by the company’s operating income or EBIT (Earnings Before Interest and Tax).

The cost of carbon, or the price paid to cover the allowance shortage, is an additional operating expense that will reduce a company’s operating income. Operating income is often referred to as operating profitability and is a measure of a company’s earning power from ongoing operations.

Operating income = operating revenue – operating expenses.

Financial information was gathered from publicly available annual reports to investors or Form 10-K filed with the SEC. We matched the revenue and operating income data to the year for which we had emissions data.

Textbox 5: Calculating carbon exposure

companies in this analysis may be able to recover more than their net costs.

All of these factors lead to a wide range in the final cost of carbon for

power companies. Southern will have the highest final carbon cost at $393 million, whereas Exelon, FirstEnergy, Edison could see the largest increases in revenue. For Exelon, this additional value could be as much as $1.7 billion.

Company Revenue Exposure Operating Income ExposureExelon -9.0% -36.3%

FirstEnergy -4.3% -19.0%

Edison -2.2% -11.2%

NRG -2.7% -10.5%

PG&E -1.3% -8.1%

Ameren -0.8% -4.3%

Progress -0.7% -4.1%

Dominion -1.3% -3.8%

MidAmerican -0.7% -3.2%

Xcel -0.3% -2.0%

ExxonMobil 0.1% 0.4%

Royal Dutch Shell 0.3% 0.5%

Chevron 0.1% 0.8%

BP 0.1% 1.1%

ConocoPhillips 0.1% 1.2%

Duke 1.0% 5.2%

AEP 1.9% 10.9%

Southern 3.3% 12.2%

Table 4: Revenue exposure and operating income exposure of main emitters

A company with a low carbon fleet may recover more

than its actual costs




Figure 7: Winners and losers in a US carbon market

First Energy

PG&E

Xcel

ExxonMobil

Shell

ChevronBP

ConocoPhillips

Progress

NRG

Dominion

Duke

Edison

Ameren

MidAmerican

Southern

AEP

-5

-3

-1

1

3

5

-38 -32 -26 -20 -14 -8 -2 4 10 16

Opera

ting incom

e e

xposure

(%

)

Exelon

-9

-7

Revenue exposure (%)

Winners and losers: Carbon exposure How are the companies in this analysis able to incorporate the cost of carbon and potential rises in carbon prices into their business fundamentals? To measure their carbon exposure, we compare the final cost of carbon to some financial performance indicators.

We have developed two carbon exposure ratios by dividing each firm’s final cost of carbon by its i) revenue and ii) operating income. Having several indicators to compare gives a more consistent analysis than using a single one (see Textbox 5).

Revenue exposure

The most exposed company is Southern, for which the final cost of carbon could represent over three

percent of its yearly revenue. AEP and Duke would see approximately 1.9 percent and 1.0 percent, respectively, of yearly revenue exposed to their final cost of carbon. Most other power sector emitters analyzed here have revenues that could increase slightly – by less than one percent. Exelon could see its revenue jump 9 percent.

Four of the five oil companies in this analysis are less than 0.2 percent exposed with regard to revenues, with Shell being the only one more exposed at 0.3 percent. This means that the final cost of carbon and the potential variation in carbon prices will only reduce at the margin

the global annual income that oil companies receive from their normal business activities.

Operating income exposure

The most impacted companies under the Kerry-Boxer bill are in the power sector. This is the sector in which we observe the highest operating income exposures, up to 12 percent. The companies whose operating income is most sensitive to the cost of carbon are Southern, AEP, and Duke. Their costs of carbon are estimated at 12, 11, and 5 percent respectively, of their operating incomes.

The power sector also contains the only companies that could see carbon costs having a positive impact on their balance sheets. The final cost of carbon for Exelon is a negative cost, or a net gain, and equals over

Southern Company has the highest oper-

ating income exposure




36 percent of Exelon’s operating income. The other companies that could experience a positive effect on operating incomes are FirstEnergy (19 percent), Edison (11 percent), NRG (11 percent) and PG&E (eight percent).

Most of the other companies have an operating income exposure close to zero. These companies, like Progress and Ameren, come out as slightly on the winning side in the first years of the program because of the coal merchant allocation, but the free allowances are quickly phased down and the gains are unlikely to last long. Regardless, their exposure is rather limited in the short term.

The operating incomes of all five of the major oil companies are less than 1.2 percent exposed to the final cost of carbon, which illustrates the limited impact of climate regulations on large oil companies’ ability to generate profits at the global corporate level. However, this same cost brought down at the refinery

level will constitute a significant share of US refineries’ net margin and could challenge the profitability – and viability – of some of these operations.

What makes a winner?

Some companies will actually be considerably better off with a US cap-and-trade program than without – Exelon, FirstEnergy, NRG and PG&E. These firms have a diversified fleet and an average emission rate lower than that of the market in which they operate. Generation fleets that include non-emitting fuels – hydro, nuclear and renewable energy – fare best, followed by fleets with low-emitting plants such as combined cycle gas turbines.

Exelon has a very low emission rate for a large amount of generation because it owns a large fleet of nuclear generators, and is therefore poised to be the biggest winner. FirstEnergy also has nuclear generation in states where coal-fired power is on the margin, and its coal-fired generation falls largely under the definition of merchant coal generation, meaning it receives a significant amount of allowances in the allocation. NRG generates approximately one half of its power from natural gas and operates mostly in PJM, where prices are frequently set by coal on

the margin. Finally, PG&E owns no coal and generates 16 percent of its electricity from hydro and 16 percent from renewable, a strategy that pays even in a state with a low marginal emission rate like California.

Companies like NRG, Edison and FirstEnergy also come out ahead for a different reason. They are bound to receive a sizable amount of allowances through the allocation to merchant coal generators, but many of their coal power plants are located in PJM. As prices are frequently set by coal on the margin in PJM, these companies would in theory also recover the costs of the allowances through the increase in electricity rates. The free allowances come as an added buffer for a few years before quickly subsiding. This buffer could help lower wholesale prices in the market, or could be used for investments in clean(er) generation to hedge risks after the free allocation is phased out.

Oil companies’ exposure is limited - not so much because of their diversified activities, but because some of them have posted record profits in the past few years. The extra expense that carbon allowances represent to these companies is only a tiny portion of their total expenses, even with the cost of EU ETS allowances incorporated. Therefore, their operating incomes are not significantly impacted. Oil companies’ exposure at the corporate level is, in our view, little affected by the fact that they need to purchase most of their allowances, as they will be able to recover most if not all of their costs through minor

In the EU ETS, power generators received allowances for free the first years of the program, covering some but not all of their emissions. Regulators were hoping the free allocation would prevent a large price increase for end-consumers as it helped mitigate the costs for generators. Reality proved different. European generators, true to economic theory, incorporated the opportunity cost of the free allowances in EU power prices. This resulted in significant electricity price increases for European ratepayers and large windfall profits for the power companies.

The allocation to LDCs in Kerry-Boxer, which must be used for consumer benefits, explicitly aims to avoid reproducing the windfall profit situation in the US.

Textbox 6: All winners with free allocation?

The final cost of carbon for Exelon is a net gain of over

36 percent of its operating income

The free allocation to merchant coal gener-ators is a deal-break-

er for several companies




price increases at the pump. Within the companies, however, refining operations are more exposed.

In both sectors, actual costs will also vary depending on a company’s offset strategy – domestic and international. If a company is able to secure low-cost offsets early on, it will be able to hedge its exposure significantly. We might see some oil companies benefit from their experience with the EU ETS and their existing involvement in the Clean Development Mechanism as a way to accumulate international offset credits early on. Similarly, some of the power companies included in this study are already investing in domestic offset projects and will likely benefit from being early movers in this field.

Finally, the exposure can be reduced by internal emission reductions, also called internal abatement. A company like Duke may be able to reduce its operating income exposure by over 15 percent thanks to the 2,300 MW nuclear plant and 5,000 MW of wind developments it has in the pipeline.

The effect of renewable energy policies on utilities will also reduce the carbon exposure of power companies, as they will be required to obtain increasing amounts of electricity from sources that do not emit carbon. Oil companies can reduce emissions from their refining emissions by improving process efficiency and thereby limit their exposure from emissions on which they cannot recover costs.

ConclusionAs the US Senate debates imposing a carbon cap in order to curb US GHG emissions, we analyzed how the mechanism actually works and how it would impact large US generators in the power and oil sector.

From an investor’s standpoint, a cap-and-trade program creates complex flows of allowances and recovered costs that can all affect the company’s bottom line. Oil companies at first appear to be very exposed because they receive almost no free allowances, but in reality their exposure is limited to their refining emissions, i.e. five to ten percent of their total emissions. Conversely, much has been said about the power sector getting a free ride, while in reality the bulk of free allowances destined for that sector will not help

large power companies exposed on the generation side.

Actual carbon exposure is a function of emissions, free allowances and costs recovered as they are passed-through to end-consumers. Oil companies will recover most if not all of the carbon costs from combustion emissions, but are exposed on their refining emissions because refineries abroad do not face the same compliance costs. Power companies with a fleet of low-emitting plants stand to be the winners in the program, while coal-based generators may not be able to recover all their costs. As the market matures, companies will be able to mitigate their exposure through internal reductions and offset investments.

Most importantly, what our numbers emphasize is the key mechanism of market-based emission reductions. Cap-and-trade programs create incentives to invest in low-carbon technologies and penalize financially the high-emitting technologies. In other words, putting a cost on emissions means giving value to reductions. In the words of Exelon’s CEO John Rowe: “The carbon-based free lunch is over.” For some companies, the low-carbon party is just starting.

Putting a cost on emissions means giv-

ing value to reductions.

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All rights reserved. No portion of this publication may be photocopied, reproduced, scanned into an electronic retrieval system, copied to a database, retransmitted, forwarded or otherwise redistributed without prior written authorization from Point Carbon. See Point Carbon’s “Terms and Conditions” at www.pointcarbon.comThe data provided in this report were prepared by Point Carbon’s Trading Analytics and Research division. Publications of Point Carbon’s Trading Analytics and Research division are provided for information purposes only. Prices are indicative and Point Carbon does not offer to buy or sell or solicit offers to buy or sell any financial instrument or offer recommendations to purchase, hold or sell any commodity or make any other investment decision. Other than disclosures relating to Point Carbon, the information contained in this publication has been obtained from sources that Point Carbon believes to be reliable, but no representation or war-ranty, express or implied, is made as to the accuracy or completeness of this information. The opinions and views expressed in this publication are those of Point Carbon and are subject to change without notice, and Point Carbon has no obligation to update either the opinions or the information contained in this publication.Point Carbon’s Trading Analytics and Research division receives compensation for its reports. Point Carbon’s Trading Analytics and Research division reports are published on a subscription basis and are not issued at the request of any client of Point Carbon.

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