a long, hot summer: a look ahead at the u.s. energy policy landscape

29
KEVIN BOOK F. CHASE HUTTO, III KEVIN M. KOLEVAR 202.506.5744 RESEARCH@CVENERGY.COM CHARTS, DATA AND FIGURES Corn Belt Politics, by the Numbers……………........... 3 • Climate Legislation: Not Exactly a “Full Auction”…4 • An “Early Warning System” for Oil Prices?.................9 • U.S. gasoline matters more than Chinese crude, currency and speculation………………....10 • “Use it or Lose it”, by the (Big!) Numbers…………….13 • Electricity: Great Moments in Eminent Domain?.……17 • Dark Clouds and Sunshine for Coal……………………….19 CAIR, CAMR, NAQQS, NSR and IGCC MACT..............21 A LONG, HOT SUMMER: A LOOK AHEAD AT THE U.S. ENERGY POLICY LANDSCAPE JUNE 2, 2009 U.S. ENERGY POLICY AND ECONOMICS ClearView Energy Partners, LLC RESEARCH SUMMARY Lawmakers have returned from Memorial Day recess, and energy legislation continues to progress through multiple House and Senate Committees. This report presents our outlook of key policy issues and related economic trends gaining momentum in the near-term. We encourage clients to contact us for follow-up or to request any additional detail regarding models or charts within this document. KEY POINTS Sailing the C’s of climate change: conservation, coal, cars … and corn. Although much attention has been lavished on those allowances allocated to industrial sectors by Waxman-Markey, the legislation that cleared the Committee also softened strictures on coal -- including relaxed New Source Performance Standards and a lower hurdle for CCS subsidies than originally established. Appeasing coal may be a necessary prerequisite for Senate passage, but it will not be sufficient until lawmakers find a workaround that accommodates ethanol's unflattering GHG emissions profile. We believe this will be a likely outcome of Agriculture Committee negotiations this month. Oil Markets: through the lenses of prices and policies. Traders educated by the school of hard knocks during 4Q09 may be working towards their Master’s degrees by taking net long positions when fundamentals of fuels and economies belie optimism, in our view. Market dynamics notwithstanding, crude’s recent rally shows all the hallmarks of being speculation-led and may give greater momentum to already-in-progress commodities and derivatives markets regulations and legislation that would establish position limits and other trading restrictions. Natural Gas: “using it or losing it” and paying more for it, too? As with the first iteration of climate legislation, we would suggest this week’s House Resources “discussion draft” may contain more negotiating collateral than politically-feasible policy with the goal of defending coal from the left and the oil patch. Waxman-Markey could still provide a vehicle for one or several of the bill’s proposed reforms, substantially deterring domestic onshore and offshore oil and gas production and shifting gas production away from federal lands. Transmission reforms: fast track or road to nowhere? Laws on the books today remain the biggest barrier to realizing widespread hopes for a grid of tomorrow. Reforms likely within the Senate Energy bill may help transmission builders navigate siting obstacles, but the broadly-inclusive, federally-supervised planning process could give opponents to new transmission a substantial new foothold for slowing or stopping lines. Back again? Clean Air Act “regulatory rebounds”. The nation’s dependence on coal as its primary source of electric power has occasioned many environmental challenges throughout the coal value chain. A reversal of ideological polarity between administrations has left several important issues very much in play, including NO x , SO 2 and mercury regulation. We anticipate a 3P rider on climate law to address uncertainty in the wake of last year’s CAIR and CAMR vacaturs. Coal: Mountaintop woes and FutureGen hopes. Ongoing conflict between the 4 th Circuit Court of Appeals and the West Virginia federal bench over mountaintop mining may not mean “business as usual”, but could actually accelerate Congressional action, catalyzing support for Rep. Frank Pallone’s (D-NJ) Clean Water Protection Act. Moreover, a once-probable presidential veto is now highly unlikely. “Old coal” and “new coal” may see divergent fates, however. The foil to a sunset for low-cost Central Appalachian production, could be burgeoning support from top Democratic policymakers for the once cash-starved FutureGen project.

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Lawmakers have returned from Memorial Day recess, and energy legislation continues to progress through multiple House and Senate Committees. This report presents our outlook of key policy issues and related economic trends gaining momentum in the near-term. We encourage clients to contact us for follow-up or to request any additional detail regarding models or charts within this document.

TRANSCRIPT

Page 1: A LONG, HOT SUMMER: A LOOK AHEAD AT THE U.S. ENERGY POLICY LANDSCAPE

KEVIN BOOK F. CHASE HUTTO, III KEVIN M. KOLEVAR 202.506.5744 [email protected]

CHARTS, DATA AND FIGURES

• Corn Belt Politics, by the Numbers……………........... 3

• Climate Legislation: Not

Exactly a “Full Auction”…4 • An “Early Warning System”

for Oil Prices?.................9 • U.S. gasoline matters more

than Chinese crude, currency and speculation………………....10

• “Use it or Lose it”, by the

(Big!) Numbers…………….13 • Electricity: Great Moments

in Eminent Domain?.……17 • Dark Clouds and Sunshine

for Coal……………………….19 • CAIR, CAMR, NAQQS, NSR

and IGCC MACT..............21

A LONG, HOT SUMMER: A LOOK AHEAD AT THE U.S. ENERGY POLICY LANDSCAPE

JUNE 2, 2009

U.S. ENERGY POLICY AND ECONOMICS

ClearView Energy Partners, LLC RESEARCH

SUMMARY

Lawmakers have returned from Memorial Day recess, and energy legislation continues to progress through multiple House and Senate Committees. This report presents our outlook of key policy issues and related economic trends gaining momentum in the near-term. We encourage clients to contact us for follow-up or to request any additional detail regarding models or charts within this document. KEY POINTS

• Sailing the C’s of climate change: conservation, coal, cars … and corn. Although much attention has been lavished on those allowances allocated to industrial sectors by Waxman-Markey, the legislation that cleared the Committee also softened strictures on coal -- including relaxed New Source Performance Standards and a lower hurdle for CCS subsidies than originally established. Appeasing coal may be a necessary prerequisite for Senate passage, but it will not be sufficient until lawmakers find a workaround that accommodates ethanol's unflattering GHG emissions profile. We believe this will be a likely outcome of Agriculture Committee negotiations this month.

• Oil Markets: through the lenses of prices and policies. Traders educated by the school of hard knocks during 4Q09 may be working towards their Master’s degrees by taking net long positions when fundamentals of fuels and economies belie optimism, in our view. Market dynamics notwithstanding, crude’s recent rally shows all the hallmarks of being speculation-led and may give greater momentum to already-in-progress commodities and derivatives markets regulations and legislation that would establish position limits and other trading restrictions.

• Natural Gas: “using it or losing it” and paying more for it, too? As with the first iteration of climate legislation, we would suggest this week’s House Resources “discussion draft” may contain more negotiating collateral than politically-feasible policy with the goal of defending coal from the left and the oil patch. Waxman-Markey could still provide a vehicle for one or several of the bill’s proposed reforms, substantially deterring domestic onshore and offshore oil and gas production and shifting gas production away from federal lands.

• Transmission reforms: fast track or road to nowhere? Laws on the books today remain the biggest barrier to realizing widespread hopes for a grid of tomorrow. Reforms likely within the Senate Energy bill may help transmission builders navigate siting obstacles, but the broadly-inclusive, federally-supervised planning process could give opponents to new transmission a substantial new foothold for slowing or stopping lines.

• Back again? Clean Air Act “regulatory rebounds”. The nation’s dependence on coal as its primary source of electric power has occasioned many environmental challenges throughout the coal value chain. A reversal of ideological polarity between administrations has left several important issues very much in play, including NOx, SO2 and mercury regulation. We anticipate a 3P rider on climate law to address uncertainty in the wake of last year’s CAIR and CAMR vacaturs.

• Coal: Mountaintop woes and FutureGen hopes. Ongoing conflict between the 4th Circuit Court of Appeals and the West Virginia federal bench over mountaintop mining may not mean “business as usual”, but could actually accelerate Congressional action, catalyzing support for Rep. Frank Pallone’s (D-NJ) Clean Water Protection Act. Moreover, a once-probable presidential veto is now highly unlikely. “Old coal” and “new coal” may see divergent fates, however. The foil to a sunset for low-cost Central Appalachian production, could be burgeoning support from top Democratic policymakers for the once cash-starved FutureGen project.

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WAXMAN-MARKEY SAILS THE C’S: CONSERVATION, CARS, COAL…AND CORN

CONCLUSION We doubt many investors will be surprised that the American Clean Energy and Security Act of 2009 (ACES), a bill that would establish an economy-wide framework for regulating greenhouse gas (GHG) emissions, will be scrutinized by multiple Congerssional committees of jurisdiction along its way to the President’s desk. Although we think the climate law already cleared its biggest hurdle in the lower chamber when it passed the House Energy and Commerce Committee by a comfortable 33-25 margin on May 21, 2009, passage through the House Floor later this summer may require the bill to shed a few more of its original provisions to squeeze by the House Agriculture Committee. This section updates our April 4 and May 18, 2009 analyses.

KEY POINTS • “C” is for “climate” and “constitutencies” and “coalition”. The big battle ahead isn’t the House Floor, in our view, but the U.S.

Senate, where each state enjoys two votes irrespective of its size, population and industrial makeup. Thus, even though ACES will probably emerge from the House structured to accommodate the environmental agendas of coastal Members (“conservation”) and urban Members concerned by economic challenges confronting large labor constituencies witin the automobile industry (“cars”), critical Senate votes will come from rural states that depend on coal mining and consumption (already the principal recipient of Chairman Waxman’s prior compromises) and corn farming. And, as we discussed in our May 6, 2009 publication (“Oil and Water”), popular sentiment, industrial consolidation and the very same demographic principles will probably make it very difficult for Senators whose states are home to crude oil

extraction to block the bill.

• Corn is still King. Agriculture Chairman Colin Peterson (D-MN) has voiced strong objections to provisions that would weaken the Renewable Fuels Standard (RFS) and establish unflattering lifecycle profiles of emissions from ethanol and other biofuels. Although ACES may already have enough momentum to garner the 218 votes needed to clear the House Floor under regular order, we believe Chairman Peterson will win modest concessions that garner additional support from farm state Members. Why? Politics, of course, not just in 2010, but also in 2012. The 10 most prolific ethanol production states account for 82% of US volumes and 127 electoral college votes (Figure 1). Writ large, the ethanol coalition may comprises as many as 30 states, taking into account the interests of second-generation biofuels derived from non-crop feedstocks, sugar producers and small business refiners who have already paid for infrastructure supporting 1G targets (Figure 2).

• What’s left to give away? Figure 3 shows how far ACES has come from the Obama Administration’s stated original goal of a “full auction” of emissions allowances. The program phases in covered sectors of the economy in three successive two-year tranches between 2012 and 2016 and, at full implementation in 2016, the current plan calls for the government to allocate 100% of allowances to covered industries for free (see our prior publications, referenced above, for details of the cap and the corresponding increase in allowable emissions offsets). The cap begins falling in 2016 towards the first interim target (17% below 2005 emissions in 2020), but the allocations remain above 95% through 2025 before stark reductions thereafter. What does this leave for ethanol? The Energy Independence and Security Act of 2007 (EISA) established three separate greenhouse gas lifecycle emissions standards for biofuels measured against conventional equivalent fuels: a 20% reduction target for first-generation (corn) ethanol, a 50% reduction for second-generation biofuels and a 60% reduction for cellulosic biofuels. EISA gives the EPA Administrator room to relax these targets by as much as 10%, an important provision given the EPA’s May 2009 EPA conclusions that ethanol enjoys only a 16% lifecycle advantage over gasoline, four percentage points short of the EISA target. We do not expect to see a rescission or a reopening of the hard-won bargain that led to EISA’s RFS increase. On the other hand, a final bargain could include one or more of: (a) a methodology that codifies a lifecycle advantage for ethanol; (b) favorable terms for crop and tree offset credits; or (c) broader administrative authority to accommodate GHG-intensive 1G biofuels than the 10% currently available to the EPA Administrator under EISA.

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• A preview of the Corn Belt counterstrike? In the spirit of historical accuracy, we note that fuel alcohols (ethanol, methanol, etc.) found their way into the nation's transportation fuels supply during the late 1970s as an energy security policy born of two major oil shocks. Although some analyses paint an unflattering emissions profile for ethanol, we expect ethanol's defenders to hearken back to this original energy security premise during debate this month. Also likely: the argument by first-generation corn ethanol producers that infrastructure directed to support corn-based volumes will provide the glide path to second-generation fuels. Energy security may be harder sell when crude and products inventories are overflowing, but three top Washington decision-makers – President Obama, his Chief of Staff Rahm Emmanuel and the #2 Senate Democrat, Dick Durbin, hail from the Illinois, the nation’s #3 ethanol producer. (More on Illinois later; there may be a common theme to policies this year).

Figure 1 – Don’t Mess With Corn: 2010 is Around the Corner (and 2012 isn’t that Far Off, Either)

Rank State 2008 Capacity

$ of US total (2008) 2008 Electoral Votes (MM g/Y)

1 Iowa 3,439 25.60% 7

2 Nebraska 1,766 13.20% 5

3 Illinois 1,135 8.50% 21

4 Minnesota 1,102 8.20% 10

5 South Dakota 885 6.60% 3

6 Indiana 848 6.30% 11

7 Ohio 529 3.90% 20

8 Kansas 508 3.80% 6

9 Wisconsin 498 3.70% 10

10 Texas 355 2.60% 34

Total 11,064 82.42% 127

Source: ClearView Energy Partners, LLC using RFA, EIA and industry data

Figure 2 – Don’t Mess With Corn, Part II: The Political Heft of the Corn Belt Encapsulates a Wide Range of 2G Biofuels Feedstocks

Ranking Second-Generation Ethanol Feedstocks First-Generation Ethanol Feedstocks Petroleum Industry Assets

Urban Wastes

Mill Wastes Forest

Residues Agricultural

Residues Switchgrass Corn

Sugar Beet

Sugar Cane

Oil Production

Refinery Capacity

1 Florida Georgia Oregon Illinois North

Dakota Iowa Minnesota Florida Alaska Texas

2 California Alabama Washington Iowa Missouri Illinois North

Dakota Louisiana Texas Louisiana

3 South

Carolina Oregon California Nebraska

South Dakota

Nebraska Idaho Hawaii California California

4 Texas Mississippi North

Carolina Minnesota Kansas Minnesota Michigan Texas Louisiana Illinois

5 New York Washington Georgia Indiana Ohio Indiana Nebraska Oklahoma Pennsylvania

6 Minnesota North

Carolina Alabama Kansas Tennessee Ohio Montana

New Mexico

New Jersey

7 Georgia California Virginia Ohio Mississippi Wisconsin Wyoming Wyoming Washington

8 Alabama Arkansas Mississippi Wisconsin Texas Missouri Colorado North

Dakota Ohio

9 Ohio Idaho Pennsylvania Texas Iowa Kansas California Kansas Oklahoma

10 Kansas Texas New York Michigan Oklahoma South

Dakota Oregon Montana Indiana

Source: ClearView Energy Partners, LLC, U.S. Department of Energy

Page 4: A LONG, HOT SUMMER: A LOOK AHEAD AT THE U.S. ENERGY POLICY LANDSCAPE

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Figure 3 – This is Not

Source: ClearView Energy Partners, LLC, House Energy and Commerce Committee

a Full Auction: % of Peak Year (2016) Regulated Allowances Allocated to Emitting Sectors, 2012-2025

LEGISLATIVE ANALYSIS: WAXMAN-MARKEY JETTISONS BILL-KILLING STANDARDS AND STRIKES A PRAGMATIC BARGAIN The following analysis presents potential areas of policy risk and/or opportunity. It is not intended to provide a comprehensive summary of the Amercan Clean Energy and Security Act (ACES), nor does it constitute a legal opinion.

American Clean Energy and Security Act of 2009 Sponsors: Henry Waxman (D-CA)* and Edward Markey (D-MA)*

* Committee Chairman

Legislative Component

Primary Tenets and/or Possible Implications; Changes from Earlier Drafts Noted Where Applicable

Cap-and-Trade • Emissions Targets (Modified): 3% below 2005 levels by 2012; 17% below 2005 levels by 2020; 42% below 2005 levels by 2030; 83% below 2005 levels by 2050.

• Auction process: Four auctions per year beginning no later than 3/31/2011; allowances auctioned can be up to four years in advance. Single round, sealed-bid, uniform price.

• Carbon census: Report by 7/1/2012 containing GHG levels 1850-present and per-country emissions for top 50 emitters. Report updated every four years; scientific data from: IPCC, EIA, NOAA, CCSP, NAS, EPA and European Union ETS. Report used to modify targets beginning 7/1/2017.

• Covered entities phase in over six years. - 2012: electricity generators, fuel importers/producers; fluorinated gas importers/producers; carbon sequestration sites. - 2014: Industrial boilers > 25,000 Mt /Y, petrochemicals, ethanol production; ferroalloy production; food processing; glass production; hydrogen production; iron and steel production; lead production; pulp and paper manufacturing; and zinc production.

55%

60%

65%

70%

75%

80%

85%

90%

95%

100%

105%

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

%of Peak Year Cap % of Annual Cap Allocated Free

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American Clean Energy and Security Act of 2009 Sponsors: Henry Waxman (D-CA)* and Edward Markey (D-MA)*

* Committee Chairman

Legislative Component

Primary Tenets and/or Possible Implications; Changes from Earlier Drafts Noted Where Applicable

- 2016: local distribution companies. • Climate registry. Reporting entities = covered entities + entities with 2008 GHG emissions >

25,000 Mt and 2008/any later year emissions > 10,000 Mt + vehicle fleets emitting > 25,000 Mt

• Regulated gases: Carbon dioxide, methane, nitrous oxide, sulfur hexafluoride, HFCs, PFCs, nitrogen trifluoride and any other anthropogenic gas where warming impact > warming impact of one Mt

/Y. 2007-2010 annual data due 3/31/2011; data due 60 days after quarter-end thereafter.

• Strategic reserve: EPA will set aside 1% of allowances between 2012-2019, 2% between 2020-2029; and 3% between 2030-2050 as a price control mechanism for supplementary options to covered entities. Position limits on strategic reserve < 10% of prior-year obligation for any purchaser.

over 100 years. EPA required to designate (or exclude) fluorinated gases as GHGs within two years of enactment. Uses global warming potential values (GWP) from IPCC AR4 to define carbon dioxide equivalence.

• Market structure: Market includes commercial and non-commercial participants. Ownership caps: 5% of any allowance auction; 10% of any regulated allowance derivative; 20% of any derivative.

• State programs: State allowances redeemable for federal allowances in proportion to acquisition and retention cost (not 1:1 swap) before 12/31/2011. Between 2012-2017, no state emissions caps allowed; states’ rights to enforce caps resume thereafter. Prohibition on state “caps” does not exclude LCFS or motor vehicle emissions standards.

• Hydrofluorocarbons (Modified): Reductions targets of 10% by 2012 (previously, 4%), 85% by 2032 (previously, 2038).

• International program aspects: Four primary elements: (1) EU ETS allowances will be redeemable for domestic compliance on a 1:1 basis; international offsets are redeemable at parity through 2018; thereafter, the exchange rate will rise to the (previous draft levels) of 1.2:1. (2) EPA may issue international offsets for projects in countries that are treaty partners with the U.S.; (3) Strategic Reserve auction revenues will finance acquisition of international deforestation credits for projects in treaty partner countries; and (4) protection for U.S. industry on a NAICS-code-level basis for sectors. Protected industries have energy intensity of production > 5%, GHG intensity of production > 5%, or (import) trade intensity of production > 15%. Firms can petition for “individual showing” for specific treatment (we think of these as “carbon rate cases”).

Renewable Electricity Standard (Modfied)

• 20% by 2020: 15% renewable sources/5% efficiency; waiver for 12%/8% • Qualifying sources: wind, solar, geothermal, biomass/landfill gas, qualified hydropower,

marine/hydrokinetic. Latest draft includes incremental hydropower since 1992 (previously cut off at 2001) and waste-to-energy (previously excluded)

• Exempts utilities below 4MM MWh/Y (previously cut off at 1MM MWh/Y) • FERC would administer credit trading program (new) • Trading credits: 1 credit per MWh except distributed generation (3 credits/MWh for first ten

years). Credits have a four-year life. • Alternative compliance payment is $25/MWh (previously, $50/MWh or 200% of allowance)

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American Clean Energy and Security Act of 2009 Sponsors: Henry Waxman (D-CA)* and Edward Markey (D-MA)*

* Committee Chairman

Legislative Component

Primary Tenets and/or Possible Implications; Changes from Earlier Drafts Noted Where Applicable

• Partial credit given for “hybrid” fossil-renewable facilities.

CCS Incentives (Modified)

• Includes carbon capture and storage wells under purview of Safe Drinking Water Act. • Two years after passage, EPA will issue standards governing CCS injections and reporting

requirements for input into/output or leakage from wells, including existing EOR facilities. • Carbon Storage Research Corporation, operated as a division or affiliate of EPRI, to be

created by 2/3 referendum of “qualified” industry participants (EEI, APPPA, NRECA and other organizations representing >20% of fossil electricity) unless > 40% of state regulators object.

• CSRC will assess between $1.0 and $1.1 billion/year of millage charges on local distribution companies as recommended by advisory council; initial rates at $0.00043/kWh for coal-fired generators; $0.00022/kWh for natural-gas-fired generators; and $0.00032/kWh for oil-fired generators. Regulated LDCs will be allowed to recover costs of millage rate.

• Commercial deployment funds will go (a) to EGUs with > 50% fossil fuel, nameplate of 250 MW or higher; (b) to industrial sources that would emit > 250,000 tpy of

. Payments will be tranched with higher payments going to higher capture rate projects. < 15% of assistance to industrial sources, and no assistance to sources of transport fuels from a solid fossil feedstock (change from those that contain > 10kg/MMBtu HHV fossil-based carbon).

New Source Performance Standards for Coal-Fired Power Plants (Modified)

• Impacts electric generators deriving >30% of annual heat input from coal, petcoke or any combination thereof at plants finally permitted after 2009.

• The requirements got looser, but more compliacted; (1) Plants finally permitted after 1/1/2020 must achieve 65% reduction compared to conventional pulverized coal, assuming < 15% carbon capture penalty; (2) Plants finally permitted between 1/1/2009 and 1/1/2020 must achieve a 50% reduction, assuming < 15% carbon capture penalty. Compliance dates are the earliest of (a) January 1, 2025; or (b) 4 years after > 4 GW of U.S. nameplate capacity (3GW electric generators and < 1 GW industrial applications, capturing and storing < 3 /Y) – and 2x250MW nameplate are injecting into underground storage other than oil or gas fields – and annual CCS is > 12

• /Y.

would not be classified as a pollutant for the purposes of section 108(a) [criteria pollutants]; section 112 [airborne hazardous materials]; or for New Source Review (protections for existing plants are strengthened in new draft).

Energy Efficiency Retrofits

• Title I creates “State Energy and Environment Development” funds (SEED funds) aggregating weatherization assistance, LIHEAP, EPCA grants, energy conservation block grants under EISA and stimulus monies. As soon as money is deposited in a SEED fund, states are in compliance with federal requirements. The draft allows broad allocation of SEED monies; they may be earmarked for specific applications or used to pay interest costs of loans for designated energy efficiency programs, lowering effective interest costs to 0%.

• Title II creates “Retrofit for Energy and Environmental Performance” (REEP) program, funding residential retrofits at $500 for energy efficiency audits; $1,000 for 10% energy consumption reductions as prescribed in the audit; $2,000 for 20% reductions; $3,000 for 20% reductions pursuant to performance-based retrofits and $150/percentage point up to a maximum of 50% of retrofit costs. In addition, REEP monies would pay for up to

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American Clean Energy and Security Act of 2009 Sponsors: Henry Waxman (D-CA)* and Edward Markey (D-MA)*

* Committee Chairman

Legislative Component

Primary Tenets and/or Possible Implications; Changes from Earlier Drafts Noted Where Applicable

$2,000/residential installation for renewable technologies not currently subsidized by tax credits.

• REEP payments for commercial buildings: $1,000 for an audit; $0.15/ for 20-30% reductions; $0.75/ for 30-40% reductions, $1.60/ for 40-50% reductions; 2.50/

for reductions > 50%.

Market Regulation (Modified)

• Regulation (Modified): FERC regulates carbon market; CFTC regulates derivatives. Tightens definition of commercial hedger for all commodities, as well.

Amendments added during May 2009 Mark-Up

• Dingell (5/19) – Establishes Clean Energy Deployment Administration, Revolving Fund for Innovative Technologies

• Sutton (5/19) – “Cash for Clunkers” program to subsidize retirement of low fuel economy vehicles

• Space (5/19) – Makes coal-fired power plants retrofitted with carbon capture and storage technologies eligible for emissions allowances

• Baldwin (5/19) – Includes solar water heating and solar light pipe as eligible efficiency sources

• Rush (5/19) – Directs > 1% of State energy efficiency/renewable energy (EERE) allowances to low-income community energy efficiency

• Welch (5/20) – Creates national energy efficiency goal > 2.5 %/Y by the year 2012 and requires that annual rate of improvement each year through 2030.

• Baldwin (5/20) – Require EPA feasibility study of carbon-labeling products w/in 18 months • Baldwin (5/20) – Rebate program for high-efficiency electric motors of between $5 and

$25/hp • Welch (5/20) – Establishes EPA program to replace inefficient wood or pellet stoves • Stupak (5/20) – Very broad

• Space (5/21) – To require regulated utilities to use emissions allowances for ratepayers’ benefit

Cease and Desist authority for FERC to halt manipulation or suspected manipulation in carbon markets (and potentially gas and power markets)

• Weiner (5/21) – Requiring frequent revision, and greater scrutiny of, EnergyStar designations

• Inslee (5/21) – Makes manufacturers of transmission equipment eligible for loan guarantees What’s Not• Inslee (5/21) – Increased federal transmission siting authority (watch this space)

In There?

• Walden (5/20) – Still-looser requirements for “renewable” biomass

Source: ClearView Energy Partners, LLC, House Energy and Commerce Committee

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OIL MARKETS AND NON-COMMERCIAL TRADING: BAD BETS ON “OIL ADDICTION” AND “RECOVERY”?

CONCLUSION We encourage investors to consider recent events in the oil markets through the two interrelated lenses of price and policy. First, the price issue. Although oil might well prove to be the first energy commodity to exhibit renewed scarcity premiums when economic recovery breathes life back into global trade and discretionary driving, we see bearish oil fundamentals ahead during the near future. With the caveat that recent reversals have made our linear regression sag like an overheated power line, our base-case projection at -0.25% 2009 global GDP contraction (OECD contraction of -2.5%) implies a CY2009 average WTI price of $55/bbl. Our “bonanza case” for a swift 2H09 OECD recovery implies a year-average price of $70/bbl. We will treat these projections in considerably greater detail in a subsequent publication. [N.B.: neither projection incorporates a significant premium from currency effects for reasons we detail below]. Second, the policy issue. Thursday, the Senate Agriculture Committee will revisit the question of whether speculation adds destructive froth to futures and derivatives markets, a topic made timely by recent progress towards a mandatory U.S. compliance market for greenhouse gas (GHG) emissions and a buoyant (and probably speculation-led) rally in crude oil futures. Executive actions to reclassify commercial traders are already underway and the new emissions market is poised to arrive with strict regulation, but we don’t think investors should rule out either administrative or legislative increases to market margin requirements and significant new compliance burdens for OTC trades.

KEY POINTS • Are traders back for a master’s degree at the school of hard knocks? Last week’s CFTC Commitments of Traders data showed

noncommercial net long positions in NYMEX light, sweet crude increasing by 4,885 contracts as commercial net short positions increased by 7,672 contracts, but it doesn't take commitments of traders data to suggest that last months’ run in oil prices probably reflects a significant portion of speculative activity. For short periods of time, speculation in financial futures may influence prices across the petroleum complex, but this influence does not last forever. One need look no further back than 4Q08 to recall what happens when speculators bet the wrong way. Neither the GM bankruptcy nor Friday’s GDP numbers posting a 1Q contraction of 5.7% seem to have tranquilized the oil bulls. It’s true that GDP numbers look backward and the market looks forward, but stable (and inauspicious) demand fundamentals for crude and products make us wonder why traders are so optimistic. If one wishes to look further, consider the implications of last summer’s reversal in the Saudi official selling price (OSP) for westbound Extra-Light crudes, a de facto two-month-forward contract (it prices for shipment, not delivery) that may well have predicted the dip in the one-month-forward NYMEX contract (Figure 4).

• China is still a drop in the barrel. Matching periods with GDP data, through 1Q09, oil products demand fell 1.2 MMbbl/d globally on a trailing twelve months (TTM) basis, according to IEA data. Although it has lost some of its global market share, the U.S. remains the fat tail of the distribution. We estimate that U.S. contractions in gasoline, jet and distillate fuels demand accounted for approximately 60% of that 1.2 MMbbl/d reduction (Figure 5). At the same time, we estimate that Chinese consumption increases over the same period accounted for approximately 120,000 bbl/d – only about 10% of the total change, and almost exactly the same proportion of lost demand as U.S. jet fuel. China's contribution to a global bid merely offsets grounded discretionary travelers. And, even with vacationers driving instead of flying, U.S. motor gasoline demand has fallen vs. year-ago levels for five straight quarters (and motor gasoline adds up to 26% of the TTM change in global products demand).

• Supply may not offer a lifeline, either. Upstream supply response takes time – particularly among OPEC producers, where

preliminary IEA data suggest volumes may have “bounced” slightly in the months between their 1Q09 bottom and OPEC’s May 28 decision to maintain current production volumes. U.S. rig counts have fallen by half during the course of the past six months and last week’s draw may have surprised some traders, but will a lower-48 drilling chill matter anytime soon? We think not, and we still see catalysts ahead for a 2009 oil glut. U.S. inventories remain 115 MMbbl above operating minimums and the much-

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ballyhooed oil floating storage – speculation in the physical product that could yet prove as wrongheaded as long financial positions could be – could add as much as another 100 MMbbl to the glut. Even if best wishes for a 2H09 recovery come true (and we would not rule out a “double dip” for the 2009 recession), even a partial destocking at fire sale prices in response to LIFO-FIFO changes during 4Q09 could break the back of the oil bid (even if real tightness might actually lie around the corner).

• The last time the dollar fell, demand soon followed. Figure 6 adjusts nominal WTI prices to account for dollar depreciation relative to the euro to make two points. First, hedging against a falling dollar may well account for some of the rapid rise in crude prices. Based on the June 1, 2009 WTI closing price of $68.58/bbl, currency effects could – under very unlikely circumstances – account for as much as $4.61/bbl. In practice, this is unlikely to be true; it’s unrealistic to use the euro as the sole basis for comparison, and the dollar was worth 7.2% more on January 1, 2007, the basis date for computing our index, than in it is today. On the other hand, a $4.61/bbl currency premium from speculative hedging seems a lot more plausible than the theoretical maximum currency effect of approximately $25/bbl implied by the dollar’s trough and crude’s peak in July 2008, so we cannot rule out the prospect that further divergence between the greenback and black gold could extend the rally. But that brings up a bigger point: a falling dollar is an ill portent for end-user and industrial demand in the world’s largest petroleum-consuming economy. A weak dollar could boost exports, but it could equally well erode disposable income available for discretionary consumption given U.S. reliance on cheap imports. Given prospects of further weakness, we think investors should differentiate the hedging value of a store of wealth like gold from an industrial feedstock like oil.

Figure 4 – Early Warning System? Saudi Official Selling Prices and WTI Contracts

Source: ClearView Energy Partners, LLC, EIA, Saudi Aramco

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Figure 5 – China Matters, but Even With Diminished Global Market Share, the U.S. Remains the Fat Tail of the Distribution

Quarterly Change vs. Year-Ago Demand

1Q08 2Q08 3Q08 4Q08 1Q09 TTM Pct of TTM

chg

US -- Gasoline (MMbbl/d) -0.12 -0.25 -0.62 -0.31 -0.12 -0.32 26%

US -- Jet (MMbbl/d) -0.06 -0.06 -0.09 -0.20 -0.16 -0.13 10%

US -- Distillates (MMbbl/d) -0.19 -0.21 -0.42 -0.22 -0.29 -0.29 23%

China -- All Products (MMbbl/d) 0.52 0.23 0.54 0.00 -0.27 0.12 -10%

Global Demand (MMbbl/d) 0.87 0.76 -0.41 -2.20 -3.10 -1.24 49%

Source: ClearView Energy Partners, LLC, EIA, IEA

Figure 6 – Implied WTI Prices Adjusting 100% for USD-EUR Differentials (January 1, 2007 basis)

Source: ClearView Energy Partners, LLC, EIA, Bloomberg

Figure 7 – It’s that Time of Year Again: Recent Milestones in Speculation Regulation

Date Event May 19, 2009 Senate approves Gary Gensler as Chairman of the CFTC.

May 13, 2009 Treasury Secretary Tim Geithner proposes electronic trading, reporting and contract standardization requirements for OTC derivatives.

April 16, 2009 International Emissions Trading Association (IETA) sends lawmakers a letter requesting CFTC regulation of carbon markets. The latest version of Waxman-Markey includes FERC regulation of the primary (physical) carbon market and CFTC regulation of derivatives markets, with all trades to be executed on exchanges.

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Date Event

March 5, 2009 Joint CFTC-Financial Services Authority task force releases report finding no evidence to support that speculation "systematically moved commodity market cash or futures prices up or down on a sustained basis".

February 1, 2009 Senator Carl Levin (D-MI) introduces the Prevent Excessive Speculation Act, a similar bill imposing position limits, requiring greater reporting requirements and limiting Foreign Boards of Trade access to electronic trading unless FBOT conforms to U.S. regulatory requirements and practices.

February 12, 2009 House Agriculture Committee votes in favor of the Derivatives Markets Transparency and Accountability Act of 2009, a bill offered by Chairman Colin Peterson (D-MN) that would establish position limits for "physically deliverable" commodities and expand CFTC's purview over OTC transactions.

December 18, 2008 President-Elect Obama chooses former Clinton Administration Treasury undersecretary Gary Gensler, one of the original proponents of commodities markets reforms that loosened regulation as CFTC chairman.

September 18, 2008 House votes 283-133 in favor Agriculture Chairman Peterson's bill imposing position limits on speculators and requiring greater regulation of OTC trading. Ultimately the Senate excludes commodities market reforms from final "extenders" and TARP legislation.

July 30, 2008 House legislation to reform commodities markets fails by a 276-151 vote (a two-thirds majority, or 290 votes, is required under "suspension" of the regular rules of order.

Source: ClearView Energy Partners, LLC, EIA, Bloomberg

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OIL & GAS ROYALTIES AND MINERAL REVENUE OVERSIGHT: THE HIGH PRICE OF USING OR LOSING

CONCLUSION Wednesday, the House Natural Resources Committee will consider “a discussion draft” of the Federal Lands and Resources Energy Development Act of 2009 (FLREDA). Like past drafts offered by Committee Chairman Nick Rahall (D-WV) during the previous Congress, we think FLREDA faces long odds on a freestanding basis and could still be a “reach” even if it is incorporated into climate law.

KEY POINTS • Policy prescription or negotiating collateral? FLREDA, much like the Waxman-Markey climate change discussion draft (ACES),

includes a wide range of policies that could deter or restrict onshore and offshore oil and gas production, and we would suggest some of the provisions included in FLREDA may be “ballast” the bill’s handlers may jettison to win compromises in negotiations ahead. Even more likely, a final ACES “Manager’s Amendment” that goes to the House Floor later this summer could adopt one or several of the key tenets of FLREDA. Even this does not guarantee final passage, however, because FLREDA could undermine the delicate balance struck by the House Energy and Commerce Committee. FLREDA could hurt independent E&Ps on a first-order basis by eroding margins with higher royalty rates and negatively impact natural gas local distribution companies (LDCs) on a second-order basis by raising the cost of natural gas. We would suggest that FLREDA’s greatest political value may be as negotiating collateral to attacks from the left and right against ACES’ coal-friendly bias.

• Across-the-board royalty hikes…with natural gas bearing the brunt. FLREDA would increase onshore oil & gas royalties from 12.5% to 18.75%, the same rate currently imposed upon GOM shallow-water production, restrict the use of royalty-in-kind payments for GOM production, eliminate royalty relief and royalty rate incentives for GOM deepwater, GOM deep gas wells in shallow water and production in the Naval Petroleum Reserve-Alaska (NPR-A) and shorten lease lives from 10 to 5 years subject to renewal at rapidly-escalating rental rates. Each of these strictures would, by itself, contribute to higher prices for domestic oil and gas production with effects likely to be disproportionately visited upon natural gas given today’s low wellhead prices, record-high inventory levels and limited ability for intermediate suppliers to diversify using overseas sources. Whereas royalty data from 2008 may appear to suggest that the U.S. federal government could be leaving money on the table (Figure 8), we aren’t so sure. Oil and gas prices are unlikely to rebound to 2008 levels as long as economic contraction persists and a practical consequence of higher federal royalties may be a production shift from federal lands (think: Rockies) to private acreage (think: shale formations).

• Two straitjackets for offshore production? FLREDA would require a “zero-emissions discharge” policy for offshore production along the Atlantic and Pacific seaboards, the Alaska federal OCS and the eastern GOM, an effective reinstatement of the moratorium that lapsed when President Bush signed the FY09 Continuing Resolution into law on September 30, 2008, because a strict interpretation of “zero-emissions discharge” could interdict ordinary deposition of drill-bit cuttings in mud. In addition, FLREDA would replace the current, top-down, Interior-led planning process for the Five Year Plan defined by the Outer Continental Shelf Lands Act with a new process that will explicitly solicit input regarding acceptable acreage for lease from four regional planning councils. Although this merely formalizes some of the informal and implicit structures of the existing Five Year Plan process, it could strengthen dissenting voices within each regional council with the practical effect of stalling or stopping leasing.

• The practical matter of federal revenues. Despite low odds for FLREDA in its current form, odds for passage could worsen

considerable depending on (a) whether FLREDA would be held to pay-as-you-go budget rules and (b) the assumptions Congress makes regarding revenue forecasts within the prescribed ten-year window. The federal government earns money from mineral leasing through three primary mechanisms: (1) rental rates; (2) royalties; and (3) “bid bonuses” at the time of auction. As depicted in Figure 8, rental payments represent a small fraction of total pro-rata revenues and, although royalties contribute the lion’s share, they are contingent payments that only arrive in the event that producers find oil and gas and develop the resources they find. 42% of the mineral revenues recorded by MMS during 2008 derived from bid bonuses from lease auctions (this is not shown in Figure 8, but Accounting Year 2008 total revenues were $24.080 billion and bid bonuses were $10.145 billion). Companies pay bid bonuses in proportion to expected production value from the tracts they lease, but also because of the option value that

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comes from choosing optimal resource deployment for exploration and production. Given the unpredictable nature of hydrocarbon deposition and petroleum geology, the value of this “real option” may be low relative to intrinsic values, but we would suggest that shorter lease life and higher royalty payments could deter bidding on, and production of, tracts where early action might be impractical and diminished optionality could lead to lower bid bonuses earned at auction.

Figure 8 – 2008 MMS Receipts from Onshore and Offshore Oil, Gas and Coal Production (Accounting Year, Ex Indian Lands)

Resource Units Total Revenues Royalties Effective Royalty %

Effective Unit Price

Onshore Coal (ton) 480,254,684 $6,109,987,638 $673,981,246 11.03% $12.72 Gas (mcf) 3,106,953,379 $20,874,029,367 $2,465,874,303 11.81% $6.72 NGL (gal) 1,926,585,237 $2,800,594,800 $278,846,008 9.96% $1.45 Oil (bbl) 108,841,808 $10,226,159,567 $1,142,310,356 11.17% $93.95

Rents $66,263,491 Offshore Gas (mcf) 1,573,046,438 $21,228,115,937 $3,067,191,883 14.45% $13.49 NGL (gal) 2,178,780,452 $3,277,817,713 $304,731,565 9.30% $1.50 Oil (bbl) 358,004,643 $35,918,453,478 $4,885,461,310 13.60% $100.33

Rents $237,074,433

Total $100,435,158,501 $12,818,396,672 Total including Rents $13,121,734,596

Source: ClearView Energy Partners, LLC

LEGISLATIVE ANALYSIS OF MAY 13, 2009 DISCUSSION DRAFT The following analysis presents potential areas of policy risk and/or opportunity. It is not intended to provide a comprehensive summary, nor does it constitute a legal opinion.

Federal Lands and Resources Energy Development Act of 2009 (Discussion Draft) Sponsor: Nick Rahall (D-WV)*

* Committee Chairman

Legislative Component

Primary Tenets and/or Possible Implications

Mineral Leasing Program

Consolidation

• Creates new Interior Department Office of Federal Energy and Minerals Leasing responsible for conventional and alternative energy leasing on the OCS, regulation of energy development on the OCS and revenue collection and auditing of Federal onshore, offshore and Indian lands.

• Organizational charter also includes responsibility to protect OCS “marine, coastal and human environment”.

Offshore Energy Development

• Five-year plan must take into account social, cultural and environmental resources of the OCS for management and timing of all renewable and nonrenewable activities

• Creates regional OCS planning process for Pacific OCS region (WA, OR, CA); Gulf of Mexico OCS region (TX, LA, MS, AL and the west coast of FL); Atlantic OCS region (ME, NH, MA, RI, CT, NY, NJ, PA, DE, MD, VA, NC, SC, GA and the east coast of FL); and Alaska OCS region.

• Regional councils will advise Interior on potential alternative and conventional energy resources in adjacent waters and create regional strategic plans that inform current federal five-year planning process.

• 10% of all offshore proceeds beginning in FY2009 into a newly-established Ocean and Coastal Trust Fund, divided as follows: 50% to Interior Secretary for grants to Coastal states;

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Federal Lands and Resources Energy Development Act of 2009 (Discussion Draft) Sponsor: Nick Rahall (D-WV)*

* Committee Chairman

Legislative Component

Primary Tenets and/or Possible Implications

30% to Ocean and Coastal Grants Program; 20% to Regional Ocean Partnerships. • Secretary of Interior will have sole authority to grant leases, easements, rights-of-way or

other activities on OCS to support production, transportation or transmission of renewable energy “from sources other than oil and gas”.

• States within 3 miles of projects will receive 27% of revenues; all states within 15 miles of the geographic center of project will receive pro rata shares of royalties.

• Transfers authority for offshore thermal energy to Interior Department from DOE. • Imposes a “zero discharge” requirement within one year of enactment for (a) areas

prohibited for production by Congressional Moratorium on September 30, 2008 (Atlantic and Pacific seaboards); (b) areas blocked by the Gulf of Mexico Energy Security Act (the Eastern GOM, essentially, which locked off everything east of the military mission line through 2022); and (c) offshore Alaska.

• Repeals EPAct05 incentives for deep well natural gas production in shallow GOM waters and deepwater royalty relief.

• Eliminates Interior Secretary’s ability to relax royalties to promote or increase production in offshore Alaska.

Onshore Energy Development

• Creates joint Energy Siting and Development Teams including BLM Director, Forest Service Chief for each of the following states: AK, AZ, CA, CO, ID, MT, NV, NM, OR, UT, WA and WY.

• Similar to regional strategic plans for OCS, each Team will assess potential energy resources, existing production and transmission infrastructure, ecological and economic factors and areas that should be removed from leasing and identify distinct zones for (a) Federal renewable energy production; (b) Federal nonrenewable energy resource extraction or mining; and (c) extraction or mining of “minerals that may be used to produce or support production of energy”. Strategic plan will be revised every five years.

• FEML will begin regular 5-year planning for onshore production in 2012, with >1 lease sale/ year in each state with lands identified as “appropriate for leasing”. FEML will take comments from any interested Federal and State agencies. State Governors will have right to appeal leasing plans until 15 days prior to submission to Congress. Attorney General and FTC will have right to approve Plan on basis of anticipated effects on competition.

• Eliminates Interior Secretary’s ability to relax royalties to promote or increase production in NPR-A and eliminates EPAct05 language that establishes a low threshold for lease extensions.

Commercial Wind and Solar Leasing

• Restricts federal easements, special-use permits and rights-of-way for commercial wind and solar projects on Federal lands and establishes “diligent development” milestones for leases.

• Leaves Interior broad leeway in establishing new leasing program, but requires royalties, rental fees, rentals, bonus bids or other payments that (a) encourage wind and solar development and (b) ensure a fair return to taxpayers.

Uranium Leasing • Partitions uranium-bearing federal lands available for existing production and any future lands into units of < 2,560 acres to be auctioned by oral bidding.

• Leases will pay > 12.5% royalty and rental fees of $2.50/acre for years 1-5 and $3/acre thereafter. Lease term will be 10 years and continue as long as uranium is produced in “paying quantities”

Oil and Gas Royalty Reform

• Penalizes violations of mineral leasing laws, failure to pay royalties, fraudulent non/under-payment of royalties or submission of false mineral royalty data with 3x royalty payments

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Federal Lands and Resources Energy Development Act of 2009 (Discussion Draft) Sponsor: Nick Rahall (D-WV)*

* Committee Chairman

Legislative Component

Primary Tenets and/or Possible Implications

for up to $25,000/violation/day or 150% of unpaid royalty amounts under $25,000. Preventing data collection carries $10,000/violation/day penalties and theft carries $25,000/violation/day penalties.

• Establishes pilot automatic data transmission for OCS oil and gas production from royalty sales meters and subsea wellhead meters.

• Limits royalty-in-kind payments for OCS leasing; they can still occur, but they cannot not part of a regular program.

“Use it or Lose it” • Defines “diligent development” for all new onshore and offshore leases, setting benchmarks to “ensure that leaseholders produce oil and gas within the original term of the lease”

• Shortens leasing period for onshore leases from 10 years to 5 years, and only subject to renewable, on an annual basis, provided that either (a) production is underway; or (b) lessee meets diligent development benchmarks and requires more time. Rental payments during extensions would be > rental rates for last year of initial period.

• Lease sales for units of < 2,560 acres (< 5,760 in AK), < 3x/year/State. Terms are > 18.75% royalty rate and minimum bids of $2.50/acre; rental rates are $2.50/acre for years 1-5 and > $3/acre thereafter for the first two years after enactment and can be raised thereafter.

• Minimum royalty in lieu of rental, > rental, must be paid at the end of each lease year on or after a discovery of oil or gas.

• “Incentive fee” (applies to onshore and offshore oil & gas leases) produced < 90 days in a calendar year $4/acre (inflation adjusted from 2009) in years 4 and 5 of the lease; and $10/acre in years 6 and thereafter.

Source: ClearView Energy Partners, LLC, House Natural Resources Committee

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TRANSMISSION REFORMS: FAST TRACK TO A NEW GRID OR A ROAD TO NOWHERE?

CONCLUSION In our view, laws on the books today remain the biggest barrier to realizing widespread hopes for a grid of tomorrow. Although reforms likely within the Senate Energy bill may improve transmission builders’ ability to navigate

KEY POINTS

-Amendment-derived [states’ rights] obstacles to interstate lines, current legislative language may introduce new impediments to construction.

• Federalization and other “power grabs” (sorry). Our April 8, 2009 publication addressed the prospect that institutional failures

and depleted state coffers would pave the way to greater federal power over traditionally state-regulated energy infrastructure. New federal siting and cost allocation authority, central tenets of the latest Senate Energy and Natural Resources Committee transmission title (summarized below) exemplify this State-Federal power shift. We would suggest that the Senate draft goes one step further by giving FERC explicit authority to coordinate planning activities previously controlled by investor-owned and municipal utilities, ISOs and RTOs, and other private-sector planning entities.

• A green light for green electrons rather than reliability? The Energy Policy Act of 2005 (EPAct05) conferred backstop siting authority for interstate lines to FERC in response to reliability concerns raised by the August 14, 2003 blackout and congestion problems dating back to the 1996 blackouts on the West Coast. Several months before DOE finalized its designation of two National Interest Electric Transmission Corridors (NIETCs) in October 2007, a large minority of House Democrats (and some Republicans) tried to use an appropriations bill to “veto” the funding for NIETC designation and FERC eminent domain powers. In addition to typical NIMBYism, opposition reflected growing concerns related to the greenhouse gas emissions from new coal-fired generation. The election of President Obama conveyed political leadership of FERC to Democrats and reversed the polarity of many of the Hill greens who once opposed greater federal incursions into state utilities regulation, especially House Energy and Commerce Committee Chairman Henry Waxman (D-CA). Previously, as Chairman of the House Government Reform Committee, Waxman held oversight hearings critical of the NIETC process but, in 2009, it was Chairman Waxman himself who added utility decoupling (encouraging states to overhaul traditional rate cases in return for federal dollars) to the American Recovery and Reinvestment Act (“stimulus package”). In our view, this improves the odds of transmission siting reform. Former opponents are now more likely to line up behind Senate Majority Leader Reid (D-NV), who has backed a symbolic, if ultimately unlikely, proposal for expediting high priority lines within “renewable energy zones” with the express intent that 75% of power would come from renewable sources.

• Planning offers a new brake pedal for transmission opponents. FERC siting authority within the latest Senate Energy draft hews closely to authority within section 7 of the Natural Gas Act, which empowers FERC to give applicants for new gas lines certificates that establish a right of eminent domain. We would suggest, however, that opponents to new lines may have gained a substantial new foothold to slowing down or stopping lines as stakeholders within the broadly-inclusive, federally-supervised planning process, in addition to input already provided under the National Environmental Policy Act (NEPA). At the risk of cynicism, we would even suggest this seems to be more a deal than a coincidence. It could be that once-vocal state and stakeholder opponents of federal siting authority conditioned their support for FERC preeminence upon a new mechanism for stalling or stopping transmission projects.

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Figure 9 – Key Moments in the Slow March to FERC Fast-Track Authority

Date Event August 9, 2009 Due date for second congestion study

TBD Oral arguments in Wilderness Society v. DOE.

May 15, 2009 AEP and Allegheny Power file application with WV PSC for Potomac Appalachian Transmission Highline (PATH), a 280-mile, 765-kV line that crosses WV, VA and MD.

May 13, 2009 Senate Energy Committee votes 13-9 in favor of amendment to Bingaman transmission bill by Senator Bob Corker (R-TN) that would weaken FERC cost allocation authority in cases where regions might bear costs "disproportionate to reasonably anticipated benefits."

May 5, 2009 Debate begins on revised Bingaman draft, which includes updated provisions for federal siting, planning and cost allocation, but draws complaints from some Committee members that siting authority is too vague.

April 30, 2009 Rep. Jay Inslee (D-WA) introduces legislation allowing transmission builders to petition directly to FERC for siting authority, under guidance of mandatory (not optional) multi-state transmission planning entities.

March 10, 2009

Senate Energy and Natural Resources Chairman Jeff Bingaman introduces his own federal siting legislation that, like the Reid bill, federalizes a portion of power line siting authority. The Senate Energy draft creates a new classification that replaces the NIETC, a “high priority transmission project” (HPTP), for which FERC will have lead agency status and conduct a single environmental review for all permitting agencies. The Bingaman draft does not set aside specific capacity or infrastructure for green power.

March 5, 2009 Senate Majority Leader Harry Reid (D-NV) re-introduces federal siting legislation that would designate "renewable energy zones" within which 75% of new transmission capacity would be reserved for green power.

February 18, 2009 Fourth Circuit Court of Appeals rejects FERC interpretation of eminent domain authority in Piedmont as overly expansive because the statute refers to permits that are "withheld" for more than a year, not permits that have been denied.

November 28, 2008 In a related matter, the Bureau of Land Management (BLM) releases its Final Programmatic Environmental Impact Statement (PEIS) designating “energy transport corridors” in 11 Western states under Section 368 of EPAct05.

September 24, 2008 Oral arguments in Piedmont Environmental Council v. FERC before the Fourth Circuit Court of Appeals, a suit contesting FERC's interpretation of its eminent domain authority

March 13, 2008 Wilderness Society petitions Circuit Court of Appeals for review of DOE order; this petition and other requests have been consolidated and are pending before the Circuit

March 11, 2008 DOE issues order denying rehearing requests and requests for stay December 3, 2007 DOE begins considerations of requests for a stay of NIETCs and rehearing of NIETC designations

October 5, 2007 DOE finalizes two NIETCs -- the Mid-Atlantic Area National Corridor and the Southwest Area National Corridor.

June 20, 2007 Energy and Water appropriations amendment by Maurice Hinchey (D-NY) to strip funding for NIETC designation (a "congressional veto") fails 174-257.

May 7, 2007 DOE releases preliminary NIETC designations.

February 6, 2007 Frank Wolf (R-VA) introduces a bill that prohibits NIETC designations within one mile of scenic, natural, historical or cultural resources and requires separate records of decision from each agency involved in permitting the line affirming environmental compliance (the opposite of an expedited review).

August 8, 2006 DOE releases its initial congestion study; studies are due to Congress every three years after the initial study.

August 8, 2005

Section 1221 of the Energy Policy Act of 2005 amends the Federal Power Act (FPA) with Section to address transmission buildout delays in congested areas. FPA Section 216 has three important tenets: (1) it requires DOE to conduct a congestion study; (2) it allows DOE to designate “national interest electricity transmission corridors” (NIETCs); and (3) it enables FERC to convey eminent domain authority over local regulators to facilitate construction of transmission lines within NIETCs where permits have been withheld for more than one year.

August 14, 2003 An electrical fluctuation leads to the shutdown of more than 500 generating units at more than 250 power plants, blacking out 45 million Americans in eight states and 10 million Canadian power customers.

Source: ClearView Energy Partners, LLC

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LEGISLATIVE ANALYSIS OF THE MAY 17, 2009 SENATE ENERGY TRANSMISSION TITLE The following analysis presents potential areas of policy risk and/or opportunity. It is not intended to provide a comprehensive summary, nor does it constitute a legal opinion.

“Title ___ -- Siting of Interstate Electric Transmission Facilities” Sponsor: Senator Jeff Bingaman (D-NM)*

* Committee Chairman

Legislative Component

Primary Tenets and/or Possible Implications

High Priority Transmission

Projects (HPTP)

• New designation for projects that are included in a regional transmission plan and > 345 kV AC or > 300 kV DC

Transmission Planning

• FERC “shall” coordinate regional planning on an interconnect-wide basis • Planning principles must be published within six months of enactment. Statute formalizes

existing relationships (a) between utilities and ISOs, RTOs, tribes and other utilities; and (b) between federal agencies, state agencies and stakeholders.

• Requires plans to consider locations of load centers and generation; demand-side management, distributed generation and “smart grid” technologies; existing plans; and costs to consumers, including “reasonable alternatives”.

• Broad FERC authority to modify intra-regional plans for consistency or to meet policy goals Siting • As with NIETCs, prospective HPTPs must attempt to work with state authorities first.

• HPTPs can petition for eligibility if (a) State fails to approve permit within one year; (b) state rejects the application (addressing Circuit ruling); or (c) State attaches “unreasonable” conditions.

Construction • FERC can authorize construction in the event it finds no suitable alternatives and believes the HPTP is necessary.

• As with Natural Gas Act Section 7 authority, FERC would issue a certificate similar in style and substance, conveying eminent domain authority to successful HPTP applicants.

Coordination and Review

• Interior Department now coordinates federal permits instead of DOE. This authority previously resided with Interior prior to EPAct05 and has been returned, but now includes other agencies that control affected lands (read: Agriculture) to submit comments.

• Interior controls NEPA as well as projects under EPAct05 Section 368 (West-ward corridor). Interior is given right to use existing Section 368 designations or create new ones

• If projects are denied or not acted upon within one year, applicant can appeal to the President, who must respond within 90 days.

Cost Allocation • Within nine months of enactment, FERC will establish cost allocation methodology and will be responsible for allocating project costs across affected states.

• Per an amendment by Senator Bob Corker (R-TN), FERC authority would be weaker in cases where regions might bear costs "disproportionate to reasonably anticipated benefits."

Source: ClearView Energy Partners, LLC

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THE “REGULATORY REBOUND EFFECT” AND COAL

CONCLUSION Legislation isn't the only game in town. Judicial rulings and executive agency actions can shift the energy policy landscape in two ways: • Directly, for example when judges vacate rulings or block actions by injunction; and • Indirectly, as when rulings and rule makings provoke Congressional responses. As we have detailed in prior publications, the Obama administration's choice to draft a GHG endangerment finding under Section 202 of the Clean Air Act on April 17, 2009 falls into the latter category. We share the consensus view that this action reflects a strategic decision taken to invoke the threats of bureaucratic constraints on local economies to catalyze Congressional response. We encourage investors not to ignore that the 1H2009 has already brought many direct impacts, as well, principally what we refer to as regulatory "rebounds" – actions taken by one administration, rejected by an appellate court and remanded back to executive agencies in the next administration for reconsideration. Coal is the common denominator. Given the nation's dependence on coal as its primary source of electric power, it should come as no surprise the coal faces environmental challenges throughout its value chain. Likewise, given the Bush administration's emphasis on liberalizing low cost energy sources and the Obama administration's concern regarding greenhouse gas emissions from fossil fuels, it should further be no surprise that a reversal of ideological polarity between successive administrations left several important coal-related issues very much in play. These include: new source review rules governing upgrades to, and expansion of, existing coal-fired capacity; regulation of nitrogen oxides and sulfur dioxide under the clean air interstate rule, or a successor regime; regulation of mercury emissions from stationary coal-fired power plants; rules governing mountaintop mining; plans for a federally-subsidized, next-generation, coal-fired power plant; and appropriate alternatives EPA must explore when considering permits for new coal-fired capacity.

KEY POINTS • Emissions trading vacatur requires “after-CAIR”. The vacatur of the Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule

(CAMR) require a successor regime at some point, but EPA faces no explicit deadline under either administrative law or existing statutes. Uncertainty isn't the only thing the way on emissions allowance prices; economic slack plays a big role, too. Notwithstanding the recent reversal of the essentially unbroken, postwar uptrend in electric power demand growth, we think ongoing discussions of emissions markets might benefit from a review the market. Figure 10 presents annual weighted average auction prices for emissions credits during the last decade. Sulfur credits appreciated at the end of last decade with the onset of the Acid Rain Program’s second phase and the drawdown of generators’ accumulated allowances. Credits rose to a significant premium in August 2005 in the wake of Hurricane Katrina when natural gas sources were shut in, forcing generators to switch to coal-fired capacity. Economic slack notwithstanding, the 2008 CAIR vacatur in 2008 essentially gutted the market for credits. Uncertainty surrounding CAIR has provoked a vast range of Hill responses. Proposals range from bills that would merely require EPA to offer a new rule by a date certain as well to those that would codify CAIR as offered by the Bush Administration. EPA's calendar suggests it will propose a revised CAIR in May 2010. We think a more likely outcome will be the inclusion of multi-pollutant regulation as an amendment within any climate law. Although the political bargains struck during Waxman-Markey obviously supersede deals made to build support for last year’s Lieberman-Warner proposal, we would suggest that Senate support for a 3P "rider" on ACES has not significantly diminished, particularly given further uncertainty regarding mercury. EPA has not even offered a proposed date to revisit CAMR, leaving the regulatory void to be filled by judicial rulings that uphold December 2000 EPA conclusion by then-administrator Carol Browner (now the White House energy and environment adviser) that mercury MACT was "necessary and appropriate". [See Figure 11].

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• Mountaintop Mining: this time, Central Appalachian resources are under the gun for real. The challenge to mountaintop mining from environmental groups that began more than a decade ago now has the explicit support from of elected officials and political appointees within every relevant regulatory sphere: the Interior Department, White House and Army Corps of Engineers, to say nothing of the EPA, which recently stalled permits for mountaintop production for additional review. Although we classify mountaintop mining under the aegis of a regulatory “rebound”, we think that, in this case, new law is increasingly likely to be the outcome likely that alters supply fundamentals. [See Figure 12]. Environmentalists have taken the Army Corps of Engineers to court many times before, but the Obama White House has already signaled its intent by immediately challenging Bush administration's Stream Buffer Zone rule. Even so, the primary theater for this battle appears to be internecine combat between federal judges. The West Virginia federal district bench continues to issue rulings curtailing mountaintop mining and challenging the validity of NWP 21 (the blanket permit the Army Corps uses to fast-track production sites) while the

• FutureGen: A ray of sunshine for (some) coal. We have stated many times that constituents whose economic livelihoods revolve around coal represent the foundation of American resource politics, but investors should not assume that the nation's different producing regions share uniform goals when it comes to mining policies or emissions controls. Just as mountaintop mining reforms would disproportionately disadvantage producers in the Central Appalachian Mountains, increased safety standards for underground mines are likely to impose greater burdens in the Illinois Basin and the near West. Likewise, although Mercury regulations are troublesome for all coal-fired generators without scrubbing capacity, they tend to be more troublesome for generators burning coal from the Powder River Basin and other Western sources, because Western coals generally contain higher fractions of elemental mercury, which flue gas scrubbers cannot clean (as a co-benefit) as easily as they capture the mercury chlorides within Eastern coal.

Circuit Court of Appeals in Richmond continues to unswervingly rule in favor of mountaintop mining by dismissing each successive appeal from West Virginia. What’s different this time? The swing factor, in our view, is political change. This year isn’t the first time Rep. Frank Pallone (D-NJ) has introduced his Clean Water Protection Act, which would reclassify mining overburden currently classified as "dredge and fill" as “waste” under a different section of the Clean Water Act, forcing EPA to regulate (read: end) the practice. Pallone has proffered his bill several times before, often in conjunction with moderate Republican cosponsors, but the near certain prospect of a presidential veto left little prospect the bill could become law. With the election of President Barack Obama on November 4, 2008, the veto has, as they say in Las Vegas, left the building. The Clean Water Protection Act now has 148 cosponsors, a gain of 28 since its last introduction one year ago, and that isn’t all it has gained. Pallone has gained a simpatico Chairman, in the person of House Energy and Commerce Committee Chairman Waxman, himself a hawk on water use and water adequacy issues, and a natural starting point for burgeoning concerns regarding water intensive energy production. Nor are the Fourth Circuit’s small victories likely to be decisive; we would suggest they may have the opposite effect of accelerating congressional action. The implication for investors: don’t bet on sustained production of the 50-70 million tons of low-sulfur, high-Btu coal produced each year from mountaintop mines.

A similar proposition holds true for technology incentives for next-generation coal-fired power plants. Low-sulfur, high-Btu coal may not be best-suited for gasification applications because it is already intrinsically valuable to electric generators. By contrast, coal with higher sulfur content (think: Illinois Basin) and lower heat content (think: PRB) may represent a better fuel for next-generation technologies like gasification, because they separate pollutants from clean synthesis gas prior to combustion and can effectively “refine” the energy embedded with an otherwise low-density source. Nor are all regions with resources that lend themselves to gasification created equal. One particular coal bearing state enjoys the backing of three very powerful advocates: Illinois, the home of the President, the President's Chief of Staff Rahm Emmanuel and #2 Senate Democrat Dick Durbin. Bush Administration fiscal concerns that led to the abandonment of its own “FutureGen” demonstration program, but Senator Durbin (with a little help from his friends) has resurrected the program and funded it with $1 billion from the February 2009 American Recovery and Reinvestment Act. [See Figure 13].

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Figure 10 – Weighted Average Annual Acid Rain

Source: ClearView Energy Partners, LLC, EPA

Figure 11 – Regulatory Rebounds for Stationary Sources under the Clean Air Act

Emissions Auction Prices, 2000-2009, $/ton

Date Event

May 21, 2009

EPA Administrator Lisa Jackson reinstates the use of the EPA "Staff Paper" in NAAQS regulatory proceedings, reaffirms the Clean Air Science Advisory Committee's (CASAC) role, and discontinues the Advance Notice of Proposed Rulemaking (ANPR). [Explanatory notes: the Staff Paper is drafted at the beginning of the formal NAAQS regulatory process and contains 1) preliminary EPA staff analysis of science and policy options, and 2) recommendations on appropriate standards; taken together, these changes increase the influence of EPA career staff and CASAC relative to public comments (for importance of this shift, see reasoning for February 24, 2009 DC Circuit Court rejection of PM-2.5 standards).

May 19, 2009 Bob Perciasepe, former Assistant Administrator for EPA's offices for Water and Air, Environmental Appeals Board Judge, and DOJ environmental prosecutor is nominated for EPA Deputy Administrator and General Counsel.

May 14, 2009 EPA Administrator Lisa Jackson remains sphinx-like regarding EPA authority to propose and implement a revised CAIR. During testimony before the Senate Interior Appropriations Subcommittee Jackson states that "there may be a need for ... a legislative fix to enable rules to go forward without additional challenges."

May 11, 2009 EPA publishes semiannual regulatory agenda; plans to propose revised CAIR in May, 2010. No plan announced for CAMR (Hg).

April 27, 2009 EPA files motion with the EPA Environmental Appeals Board for a voluntary remand of the air permit issued to the Desert Rock Energy Facility in NM; this permit had been issued July 31, 2008, and had been challenged on the grounds–among others–that EPA should have considered emissions in the permit process.

April 24, 2009 EPA announces it will reconsider aspects of Bush-era NSR permitting regulations on "fugitive emissions," the "reasonable possibility [of air quality deterioration]" recordkeeping trigger and implementation of fine particulate matter ("PM2.5") permitting.

March 24, 2009 EPA Acid Rain auction prices nosedive due to regulatory and economic uncertainty; average spot price is $69.74, down from $390 in 2008.

March 9, 2009 In a letter to EPA Administrator Lisa Jackson, air regulators from 17 states (CT, DE, IL, IN, ME, MD, MA, MI, NH, NJ, NY, OH, PA, RI, VT, VA, WI) and the District of Columbia outline plans to comply with federal air quality standards and assist EPA in designing a revised CAIR.

March 5, 2009

D.C. Circuit Court of Appeals remands the EPA denial of North Carolina's Section 126 petition regarding fine particulate matter ("PM2.5") and ozone to EPA for administrative reconsideration. EPA had requested this action between the DC Circuit's July 11, 2008 decision vacating CAIR and its December 23, 2008 order reinstating the rule pending further administrative action.

February 24, 2009

DC Circuit Court of Appeals remands EPA's 2006 NAAQS fine particulate matter ("PM 2.5") standard for further proceedings, calling the standards "in several respects, contrary to law and unsupported by adequately reasoned decision-making. . .". The Court highlights contrasts between the rejected standards and those recommended by EPA Staff and CASAC; the Court allows the NAAQS PM-Coarse standard to stand.

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Date Event February 23, 2009 Supreme Court accedes to EPA request and denies industry request for review of CAMR vacatur. February 6, 2009 EPA asks the Supreme Court to dismiss its prior request for review of the DC Circuit Court's vacatur of CAMR.

January 7, 2009 EPA directs regional offices to strictly apply Clean Air Act MACT requirements to coal and oil-fired power plants as the result of the DC Circuit Court of Appeals February 8, 2008 decision vacating CAMR; this vacatur remains on appeal to the Supreme Court.

January 7, 2009 Senate EPW Clean Air Subcommittee Chairman Tom Carper (D-DE) indicates willingness to move 3P bill in 2009 ( , , Hg) if necessary, stating: "I'm not sure how many people died last year from climate change".

Janury 1, 2009 Pennsylvania begins implementation of CAIR standards; implementation deadline: 2010

December 23, 2008 D.C. Circuit Court of Appeals reverses June 11 CAIR vacatur, allowing reinstatement of the rule without deadline while EPA “fixes the rule.”

December 15, 2008 EPA issues interim final rule restoring sulfur emissions credit trading under the Acid Rain program (which had been subsumed by CAIR).

December 10, 2008 Citing uncertainty over the fate of CAIR, EPA abandons regulation for hourly (instead of annual) New Source Review emissions test.

December 2, 2008 U.S. District Court for Asheville, NC, rules that Duke's Cliffside Unit 6 plant must submit to a formal MACT determination for mercury.

December 2, 2008 Supreme Court moves initial response deadline for EPA request for CAMR reinstatement to January 21, 2009.

November 17, 2008 EPA requests that D.C. Circuit Court of Appeals stay the decision striking CAIR until EPA can issue a replacement.

November 5, 2008 22 States petition the D.C. Circuit Court of Appeals to temporarily reinstate CAIR.

October 21, 2008 D.C. Circuit Court of Appeals requests additional information, suggesting that it may grant request for a stay or reinstatement.

October 17, 2008 EPA appeals CAMR ruling to Supreme Court. September 24, 2008 EPA requests a rehearing of the North Carolina v. EPA case from the US Circuit Court of Appeals for D.C.

September 17, 2008 Legislative attempts to codify CAIR falter when House Republicans, defect, led by Energy and Commerce Committee ranking member Joe Barton (R-TX), who vows to "revisit the entire Clean Air Act" in the 111th Congress.

Early September 2008

House and Senate Democrats attempt to forge consensus on a short-term legislative fix to CAIR, and even Senate Environment and Public Works Committee Chairman Jim Inhofe (R-OK), a veteran of the 2005 showdown over Clear Skies, shows a willingness to join a consensus.

August 11, 2008 EPA asks D.C. Circuit Court of Appeals for an extension until September 24 for CAIR appeal and September 17 for CAMR.

July 29, 2008 Senate Environment and Public Works subcommittee hearing explores "four-pollutant" or "three-pollutant" alternatives to CAIR and CAMR, or potential codification of CAIR Phase I and/or Phase II.

July 16, 2008 Environmentalists sue to block construction of Duke's Cliffside Unit 6 boiler on the basis that it does not meet MACT standards for mercury.

July 11, 2008 D.C. Circuit Court of Appeals overturns CAIR on the basis of its "more than several fatal flaws." May 20, 2008 D.C. Circuit Court of Appeals denies EPA/industry petition to reconsider CAMR vacatur.

May 6, 2008 Sierra Club threatens to sue developers of future power plants on the basis they have inadequate mercury emissions controls.

April 28, 2008 EPA formally approves AL, AR, FL, GA, IL, IA, KY, LA, MA, MO, MS, and VA state implementation plans (SIPs) as compliant with CAIR requirements, eliminating need for Federal Implementation Plans (FIPs) for those states.

April 18, 2008 D.C. Circuit Court of Appeals orders reinstatement of Clinton-era mercury requirements, per March ruling. March 25, 2008 North Carolina v. EPA oral arguments.

March 24, 2008 EPA and Utility Air Regulatory Group file separate motions for review of appellate court decision rejecting CAMR.

March 17, 2008 D.C. Circuit Court of Appeals orders case-by-case MACT reviews of coal-fired power plant permit proposals. February 14, 2008 Senator Carper (D-DE) introduces Mercury Emissions Control Act (S.2643) as alternative to CAMR. February 8, 2008 D.C. Circuit Court of Appeals vacates CAMR in New Jersey v. EPA.

December 6, 2007 New Jersey v. EPA oral arguments.

November 16, 2007 EPA credits CAIR as contributing to 2006 being the most successful year in reductions of pollutants that cause acid rain.

July 11, 2007 Four environmental advocacy groups file brief with D.C. Circuit Court of Appeals arguing CAIR will

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Date Event significantly improve air quality.

October 17, 2007 EPA amends CAIR FIP provision to allow immediate nullification of FIP upon SIP that complies with CAIR reduction targets.

June 1, 2007 Bush Administration petitions court to dismiss North Carolina v. EPA.

May 7, 2007 EPA denies North Carolina petition for reconsideration of March 2006 FIP decision and reiterates that FIPs are sufficient to eliminate downwind nonattainment effects.

April 25, 2007 Senator Sanders (I-VT) introduces multi-pollutant legislation (S.1201). April 20, 2007 Senator Carper (D-DE) introduces multi-pollutant legislation (S.1177).

March 19, 2007 Reps. Allen (D-ME) and Walsh (R-YA) introduce mercury monitoring proposal (H.R.1533). March 12, 2007 Sens. Collins (R-ME), Clinton (D-NY) and Lieberman (I-CT) introduce mercury monitoring proposal (S.843). March 2, 2007 Ozone Transport Commission calls for reductions beyond CAIR targets.

January 9, 2007 Senator Collins (R-ME) demands 90% nationwide mercury emissions cuts.

January 1, 2007 Article in Bioscience argues five mercury "hotspots" between Adirondacks and Nova Scotia exceed government limits for mercury concentrations safe for fish and wildlife. Conclusion contests the EPA and industry argument that CAMR would not cause hotspots.

November 15, 2006 American Medical Association opposes CAMR. July 21, 2006 National Academy of Sciences reports that >60% of U.S. coal-fired power lacks necessary and SO2 controls.

July 1, 2006 National Wildlife Federation report suggests 27 states will meet CAMR Phase 1 mercury budget (2010) and only seven will meet Phase 2 (2018).

April 13, 2006 Federal court orders EPA to disclose two computer simulation models used to develop CAMR. March 15, 2006 EPA denies Connecticut and Texas CAA Section 126 petitions.

January 30, 2006 North Carolina sues Tennessee Valley Authority on the basis that CAIR allowances in lieu of retrofits lead to downwind pollution.

June 26, 2006 North Carolina AG files North Carolina V. EPA over March 2006 petition denial. November 23, 2005 The EPA agrees to review formulas in CAIR to determine sulfur dioxide and nitrogen oxide emission credits.

September 21, 2005 Brookhaven National Laboratory study suggests "no correlation" between modeled mercury deposition and soil/vegetable concentrations, the linkage implied by "hotspots."

July 11, 2005 12 industry lawsuits filed over CAIR with U.S. Circuit Court of Appeals for D.C.

July 8, 2005 NC submits a petition for review against the EPA with D.C. Circuit Court of Appeals and a petition for reconsideration with the EPA requesting administrative review of CAIR.

March 15, 2005 EPA finalizes Clean Air Mercury Rule (CAMR) and reverses December 2000 Clinton-era EPA finding under Section 112 that regulating mercury emissions from utilities is "appropriate and necessary."

March 10, 2005 The EPA finalizes the Clean Air Interstate Rule (CAIR).

March 18, 2004 NC Attorney General Roy Cooper (D) petitions the EPA for assistance in reducing emissions from 13 “upwind” states (AL, GA, IL, IN, KY, MD, MI, OH, PA, SC, TN, VA, and WV) under the authority of Section 126 of the Clean Air Act (addresses emissions originating across state lines).

Source: ClearView Energy Partners, LLC, drawing from media and government sources

Figure 12 – Key Moments in Mountaintop Mining

Date Event

May 29, 2009 The 4th Circuit Court of Appeals denies a motion to reconsider its February 13, 2009 decision overturning the Federal District Court the March 23, 2007 Chambers ruling that the Army Corps of Engineers was not performing adequate environmental analyses before issuing mountaintop mining permits.

April 27, 2009

Interior Secretary Ken Salazar announces his intent to file a plea in federal district court in Washington DC seeking to vacate and remand the Bush Administration's Stream Buffer Zone rule; Salazar noted in his announcement that "[t]oday we are taking another step toward changing how the department of Interior does business and cleaning up a major misstep from the previous Administration. . ." and "I don't see this particular action today having an effect on coal production."

March 31, 2009

The Federal District Court in the Southern District of West Virginia (Judge Goodwin) vacates an Army Corps of Engineers' decision to issue a nationwide permit authorizing discharge of dredge and fill materials associated with surface mining (including mountaintop mining), and remands the permit to the Corps for further proceedings under Section 404 of the Clean Water Act. An appeal by the Corps would be to the 4th

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Date Event Circuit Court of Appeals.

March 25, 2009 Senators Ben Cardin (D-MD) and Lamar Alexander (R-TN) introduce S. 696, the Appalachia Restoration Act, which reclassifies dredge-and-fill as waste (forcing a section 402 classification under CWA). At last count, this bill had 5 cosponsors.

March 24, 2009 EPA Administrator Lisa Jackson expresses concern to Army Corps of Engineers over the need to reduce the potential harmful impacts of mountaintop mining on water quality, directs EPA to review pending permit requests for environmental concerns.

March 4, 2009 Representatives Frank Pallone (D-NJ) and Dave Reichert (R-WA) introduces H.R. 1310, the "Clean Water Protection Act", which reclassifies dredge-and-fill as waste (forcing a section 402 classification under CWA). At last count, this bill had 148 cosponsors.

February 13, 2009 The 4th Circuit Court of Appeals in Richmond, VA overturns a federal district court ruling in the Southern District of West Virginia (Judge Robert Chambers) that the Army Corps of Engineers was not performing adequate environmental analyses before issuing mountaintop mining permits.

December 22, 2008 Eight environmental groups file lawsuit in federal district court in Washington, DC challenging the Stream Buffer Zone Rule.

December 12, 2008

Department of the Interior-Office of Surface Mining publishes the final Excess Spoil, Coal Mine Waste, and Buffers for Perennial and Intermittent Streams Rule ("Stream Buffer Zone Rule"), effective date: January 12, 2009. The rule would extend the buffer zone to all waters (ponds, lakes, marshes), permitted additional activities, and allowed exemptions to the rule where an alternative was not reasonably possible.

December 4, 2008 Bank of America announces it will phase out lending to companies whose predominant method of extracting coal is through mountaintop mining.

December 2, 2008 EPA Administrator Steve Johnson clears the Stream Buffer Zone Rule after securing agreement from OSM that no mining activity potentially affecting water quality may proceed unless approved under the Clean Water Act.

October 17, 2008 Department of the Interior-Office of Surface Mining publishes final 1,768-page EIS on Stream Buffer Zone Rule; comment period open through November 23, 2009.

October 2, 2008 Judge Chambers hears arguments from the Ohio Valley Environmental Coalition and Fola Coal Company over Army Corps mountaintop mining permits for Fork No. 1 and 2 mines in Nicholas and Clay Counties, WV.

September 23, 2008

4th Circuit Court of Appeals (Richmond) hears oral arguments on the four Section 404 valley fill permits rescinded in a March 23, 2007 court ruling. The court selected three judges, who listened to attorneys' arguments and presentation of merits for about 90 minutes. The judges are: Michael (WV), most senior on the panel, has previously voted against mountaintop mining; Shedd (SC), who has voted for MTM; and Gregory (VA), who previously recused himself due to a conflict of interest.

August 11, 2008

West Virginia District Court Judge Robert Chambers temporarily blocks a Clean Water Act Section 404 mountaintop mining (MTM) permit for Patriot Coal’s Hobet 22 (400-acre Hobet 21 expansion). The expansion project was already underway using a June 2007 state permit and a CWA Section 404 permit issued by the U.S. Army Corps of Engineers on August 1, 2008. A formal hearing is held about one week later.

April 29, 2008 Penn Virginia operating Co. LLC and Coal River Mining LCC (coal operator) agree to limit development work at Nellis surface mine, Boone County, WV, during court proceedings.

April 23, 2008 Tyler Morgan, Independence Coal, and Fola Coal accept limits on fill construction activity on WV mines and limits on areas in WV where permitted to dump waste as part of mountaintop removal mining during court proceedings, which allowed companies to avoid temporary restraining order from Judge Chambers.

April 18, 2008 Judge Chambers issues order calling for temporary restrictions on use of 3 coal mining valley fill permits in southern WV (issued to Tyler Morgan LLC, Independence Coal Co. Inc. unit of MEE, and Fola Coal) while court proceedings continue.

October 16, 2007 Judge Chambers allows MEE subsidiary Independence Coal to dump overburden at Laxare East in Boone County. Mine idle at time of Judge Chambers’ March 23, 2007 ruling.

October 11, 2007 Judge Chambers issues temporary restraining order and preliminary injunction to block formation of valley fill at Callisto Surface Mine, operated by Magnum Coal subsidiary in Boone County.

October 9, 2007 4th Circuit Court of Appeals takes up Chambers’ March 23, 2007 decision.

September 13, 2007 Judge Chambers grants motion to stay his June 13, 2007 order pending appeal (see below), but denies plaintiffs’ motion to reconsider his decision regarding discharge of pollutants into streams.

August 24, 2007

U.S. Office of Surface Mining issues proposed rule extending stream buffer zone (100 feet) to all waters (not just streams), but exempting “permanent excess spoil fills and coal waste disposal facilities,” as well as damage promised to be repaired at later date. Public comment period closed January 28, 2008 after being extended three times since October 2007.

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Date Event

July 12, 2007 Judge Chambers clarifies applicability of his March 23 and April 6 orders: existing valley fill areas (or their discharges) must be considered under separate appeal.

June 20, 2007 Massey and other intervenor-defendants file memorandum asking Judge Chambers to alter his 3/23/2007 and 4/6/2007 orders enjoining filling activities at Camp Branch Mine (and others) to reflect decision to allow continued use of existing valley fills because harm to streams already occurred.

June 19, 2007

OVEC files 4th and 5th supplemental complaints calling for 4CCA to require Corps to rescind CWA Section 404 permits for Mingo Logan's Spruce No. 1 Mine, as well as Arch Coal's (Coal Mac) Phoenix No. 5 Mine, Independence Coal's Falcon Mine, and Callisto Coal's Callisto Surface Mine. Supplemental complaints suggest Corps has not adequately assessed cumulative impact, nor does Corps have jurisdiction to issue CWA Section 404 permits for pollutant discharge that does not qualify as "fill material."

June 13, 2007 Judge Chambers grants OVEC's motion for partial judgment, finding that Corps does not have authority to permit discharge of pollutants into stream segments below valley fills.

June 5, 2007

OVEC files supplemental complaint to declare NWP 21 contrary to CWA Section 404 and prohibit Corps from issuing further permits without conducting appropriate EIS. Complaint cites array of environmental issues associated with NWP 21 permitting and alleges that Corps has no basis for minimal environmental effects determination. Plaintiffs question Corps' limiting filling of stream bed under 2007 NWPs 29, 39, 40, 42, and 43, but not NWP 21.

May 4, 2007 Reps. Chris Shays (R-CT) and Frank Pallone (D-NJ) re-introduce legislation reclassifying dredge-and-fill as waste (forcing a section 402 classification under CWA). Clean Water Protection Act (H.R. 2169) has 128 co-sponsors.

May 2, 2007 4th Circuit Court of Appeals (4CCA) grants appeal; Court formally opens case on 6/1/2007.

April 30, 2007

In response to OVEC's challenge to three nationwide permits (4/9/2007), Corps acknowledges it violated CWA Section 404(e) when issued eleven authorizations under 2002 NWP 21, but asserts that plaintiffs can use Rule 15(d) to "introduce a separate, distinct, and new cause of action" (issues with 2007 NWPs 21, 49, and 50 should be taken up in a separate case).

April 19, 2007 OVEC submits motion requiring Corps to suspend another NWP 21 authorization for Apogee Coal's North Rum Surface Mine in Logan County, WV, alleging continued authorization would allow discharge of 49 million cubic yards of dredged or fill material into nearby U.S. waters. Plaintiffs' complaint withdrawn on 5/29/2007.

April 17, 2007 U.S. District Court Judge Chambers allows MEE to continue producing on three of four permit sites blocked by 3/23/2007 ruling pending MEE's appeal, likely reflecting broader political sensitivity to job losses in area.

April 16, 2007

OVEC files additional claim to rescind individual permits issued to (1) Coal-Mac for Phoenix No. 5; Independence Falcon Surface Mine; and (3) Jupiter Holdings for Callisto Surface Mine on basis that permits "reflect a continuing pattern and practice by the Corps of issuing illegal permits that suffer from the same defects that this court identified in its March 23, 2007" ruling.

April 11, 2007 Massey requests, while Corps and company appeal March 23 and April 6 rulings, Court (1) lift injunctions denying four valley fill permits; and (2) enable, at very least, use of previously-filled sites for deposition of overburden.

April 10, 2007 MEE files with Court affidavit stating 66 employees laid off with more to follow if work does not resume.

April 9, 2007 OVEC submits memorandum to Judge Goodwin - unsurprisingly - making point that, because Corps made some of same "fundamental assumptions" in issuing NWP 21 that did in issuing individual permits [rescinded by Chambers], NWP is equally flawed. Corps responded on 4/30/2007.

April 9, 2007

OVEC re-alleges allegations made during Goodwin case (OVEC v. Bulen) by filing complaint that Corps violated Administrative Procedure Act, Clean Water Act and National Environmental Policy Act by reissuing NWPs 21, 49 and 50 (related to dredge or fill discharge) and requests injunctions blocking further surface mining under NWPs 21, 49 and 50 in WV.

April 6, 2007

U.S. District Court Judge Chambers tells MEE cannot continue mining activities under rescinded permits, even if, overburden dumped on sites of two previously-completed valley fill operations. Chambers dismisses MEE argument that Corps no longer has authority over those prior permit sites (because streams are dead) and therefore no official approval would be required on grounds that cumulative impacts of "ad hoc modification have not been studied."

March 26, 2007 U.S. District Court Judge Goodwin asks plaintiffs and defendants to file supplementary memoranda incorporating Judge Chambers' 3/23/2007 finding.

March 23, 2007

U.S. District Court Judge Chambers rules Corps has not adequately considered cumulative effect of blocking intermittent and perennial streams on downstream aquatic environment when issuing four site-specific permits to MEE during 2005 and 2006, rescinds the permits and requires MEE to stop production on sites governed by four permits. Requests that Corps return with explanation for why their assessment of

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Date Event environmental impact was adequate.

March 18, 2007 Expiration of 2002 NWP 21. March 9, 2007 Corps reissues NWP 21, effective March 19, 2007 and expiring March 18, 2012.

February 2006 Full 4th Circuit refuses to reconsider panel decision by 5-3 margin (N.B. all three judges voting to reconsider are Democrats; all five voting against are Republicans).

November 2005 District court judgment overturned and NWP 21 judgment lifted, ruling that Corps complied with CWA in its NWP 21 rules.

June 2005 OSM decides to hold off on finalizing stream buffer zone rule and suggests new regulation will be issued in conjunction with new EIS.

May 2005

Corps, EPA and Interior Department issue final programmatic EIS establishing "preferred alternative" that OSM, Corps, EPA and state agencies determine size, number and location of valley fills under joint permit application that integrates CWA and SMCRA and Corps will have authority to make case-by-case determinations whether to cover each project under NWP 21 or site-specific section 404 permits.

July 2004 U.S. District Court for Southern District of WV (Judge Goodwin) rules that NWP 21 cannot be used for mountaintop mining and rescinds 11 valley fill permits issued under NWP 21(provided are not already under construction by July 8, 2004).

January 2004 OSM proposes changes to stream buffer zone rule.

October 2003 WV environmental group files case in U.S. District Court for Southern District of WV that NWP 21 cannot be used for mountaintop mining because of greater than "minimal impact" on environment.

August 2003 Court enjoins six more valley fill permits.

May 2003 Corps, EPA and Interior Department issue draft programmatic EIS for mountaintop mining as promised in December 1998 partial settlement. Draft EIS calls for Interior Office of Surface Mining (OSM) to change stream buffer zone rule for consistency with Clean Water Act.

February 2003 Reps. Chris Shays (R-CT) and Frank Pallone (D-NJ) propose "Clean Water Protection Act of 2003", which would codify Haden decision into permanent law. Effort draws sixty-four cosponsors but ultimately fails.

January 2003 U.S. Court of Appeals for 4th Circuit overturns Judge Haden's decision.

June 2002 EPA and Corps issue new regulations defining "discharge of fill material" which have stood without successful legislative challenge to present time.

May 2002 U.S. District Court for Southern District of WV (Judge Haden) rules Congress never intended CWA permitting under section 404 solely for waste and permits issued under Section 404 during past twenty years are illegal - fills only allowed for "legitimate post-mining land use".

January 2002 Supreme Court refuses to take 4th Circuit case and verdict holds (industry wins).

August 2001 "Kentuckians for the Commonwealth" sues Corps charging specifically that single section 404 permit is illegal on similar grounds to Bragg (waste should be regulated by EPA).

April 2001 U.S. Court of Appeals for 4th Circuit reverses October 1999 injunction on states' rights basis, ruling WV, not EPA, has jurisdiction and case should not be brought in federal court.

April 2000 EPA and Corps propose to revise regulations implementing Section 404 of Clean Water Act so that mining spoil will be considered "dredge and fill material" (regulated under Section 404 of the CWA), not "waste material" (regulated under much more-stringent section 402).

November 1999 Senators Robert Byrd (D-WV) and Larry Craig (R-ID) offer rider to appropriations bill that would have allowed valley fill to continue; legislative effort fails.

October 1999 U.S. District Court for Southern District of WV (Judge Haden) blocks fill of larger WV streams by ruling overburden should be classified as "waste material" (requiring section 402 permits) instead of "dredge and fill material" (which EPA and Corps jointly permit under CWA section 404).

December 1998 Federal agencies agree to complete EIS on mountaintop mining and Corps agrees valley fills in WV watersheds of at least 250 acres will be individually permitted (not under NWP 21).

July 1998

WV citizens' group sues state of WV and Corps, claiming state had violated Surface Mining Control and Reclamation Act by failing to enforce 100-foot "buffer zone" around intermittent and perennial streams. Lawsuit also charges that Corps (1) was granting permits for waste disposal (they do not have this authority under CWA section 404) and (2) was issuing permits under NWP 21 that have greater than legal standard of "minimal adverse effects, individually and cumulatively".

Source: ClearView Energy Partners, LLC, drawing from media and government sources

Figure 13 – A Bright Future for FutureGen?

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Date Event October, 2009 IEA to release an international "roadmap" to build 20 CCS demonstrations.

May 27, 2009

DOE establishes National Carbon Capture Center (NCCC) in Wilsonville, AL, to develop and test pre-and post-combustion technologies to capture from coal-fired power generation. The NCCC will be managed and operated by Southern Company, and includes as participants American Electric Power, Luminant, EPRI, Arch Coal, Peabody Energy, and RioTinto.

May 15, 2009

Energy Secretary Steven Chu details plans for spending $2.4 billion in stimulus funds on CCS during In remarks before the National Coal Council, including $800 million in Clean Coal Power Initiative (CCPI) projects; $1.52 billion for CCS proposals for range of industrial sources, including power generation, cement plants, manufacturing and other sites; $50 million for geologic site characterization, and $20 million for education and training of geologists, scientists, and engineers. Approximately $1 billion remains of the $3.4 billion the stimulus provided for CCS programs, which according to a DOE spokeswoman, "was set aside to be used for the FutureGen project if the Secretary decides to pursue the FutureGen project."

May 14, 2009

DOE's National Energy Technology Laboratory releases Storage of Captured Carbon Dioxide Beneath Federal Land as a follow-on to the November, 2008 Carbon Sequestration Atlas of the United States and Canada. DOE estimates Federal lands hold the potential for between 126-375 billion metric tons of , 85% of which is west of the Mississippi River.

April 24, 2009

EPA files request for a remand of Desert Rock's July 31, 2008 permit, notes that "Region 9 seeks a voluntary remand in this matter so that it may reconsider its decision to exclude IGCC from further analysis in the top-down BACT review for the Desert Rock project..." This permit had been the subject of appeal based on its lack of consideration for emissions. Could this be the warm-up for IGCC as BACT for coal?

April 22, 2009 FERC Chairman Jon Wellinghoff tells a U.S. Energy Association forum: "We may not need any [new US coal or nuclear plants], ever."

March 11, 2009 GAO reports a $500 million math error led to the cancellation of FutureGen in 2008; According to GAO, the inflation-adjusted cost of the project escalated from $950 million to $1.3 billion over 4 years, rather than to the $1.8 billion suggested by the DOE analysis.

February 17, 2009 President Obama signs American Recovery and Reinvestment Act into law; included is $3.4 billion for DOE's Fossil Energy CCS activity.

November 4, 2008 Illinois wins the election? U.S. Senator Barack Obama (D-IL) elected President; Senate Majority Whip ( #2 Democrat) Dick Durbin (IL) re-elected; Representative Rahm Emmanuel (D-IL 5th Congressional District) is later named White House Chief of Staff.

November 17, 2008 DOE's National Energy Technology Laboratory releases Carbon Sequestration Atlas of the United States and Canada; estimates more than 3,500 billion metric tons of storage potential in U.S. and Canadian oil and gas reservoirs, coal seams and saline aquifers.

October 8, 2008 Application due date for DOE Restructured FutureGen solicitation.

September 30, 2008

President Bush signs the Continuing Resolution (CR); Senate Majority Whip Dick Durbin (D-IL) succeeds in limiting FutureGen to $134 million through March, 2009 via the CR, keeping the project alive but limiting availability of funds that could otherwise divert the project from the Mattoon, IL site--and putting the ultimate decision on FutureGen in the hands of the next Congress and Administration.

September 22, 2008 DOE announces solicitation for $8 billion in EPACT Title XVII loan guarantees for projects that employ advanced technologies to avoid, reduce or sequester emissions of air pollutants or greenhouse gases in coal-based power generation, industrial gasification, and advanced coal gasification facilities.

June 24, 2008

DOE announces final Restructured FutureGen program application requirements; initial tranche of $290 million solicitation (at 50-50 cost share) available for projects including: a demonstration power plant w/CCS, or a CCS retrofit to an existing unit; projects to quantify and assess capture, transport, and storage; and a public education plan regarding sequestration risks. Pulverized coal CCS projects eligible for funds.

June 15, 2008 DOE officially withdraws funding from original FutureGen project.

May 21, 2008 Provision to extend FutureGen Industrial Alliance Inc.'s cooperating agreement with DoE until next year removed from Senate Appropriations Committee Iraq war supplemental.

May 8, 2008 Senate Appropriations Subcommittee on Energy and Water Development questions DoE Secretary Bodman on restructuring of FutureGen.

May 7, 2008 DOE releases "draft funding opportunity announcement" as part of solicitation process for clean coal power plants, restructured FutureGen project. DOE accepts public comments on FOA for 2 weeks, until May 21.

April 15, 2008 House Subcommittee on Energy and Environment hosts DOE Undersecretary Bud Albright in hearing investigating restructuring of FutureGen project.

April 9, 2008 DOE's Joseph Strakey, Jr. reveals restructured FutureGen will require additional years to implement carbon capture technology.

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Date Event

February 4, 2008 President Bush releases FY2009 budget proposal, including $648 million for DOE Office of Fossil Energy advanced coal program ($156 million for FutureGen).

January 30, 2008

US Secretary of Energy Bodman announces restructured approach to FutureGen, including plans to add carbon capture and sequestration (CCS) technology to multiple commercial-scale (> 300 gross MW) integrated gasification combined cycle (IGCC) plants. Restructured plan would not proceed with FutureGen project in Mattoon.

January 30, 2008 DOE issues Request for Information (RFI) for industry comments on restructured FutureGen approach (deadline: March 3, 2008); RFI notes new focus on CCS and exclusion of hydrogen production, despite original FutureGen concept's inclusion of such technology.

December 18, 2007 FutureGen Alliance selects Mattoon, Illinois as site for FutureGen project.

December 18, 2007

DOE Acting Principal Deputy Assistant Secretary for Fossil Energy James Slutz issues statement on FutureGen: ". . . projected cost overruns require a reassessment of FutureGen's design . . . DOE believes that the public interest mandates that FutureGen deliver the greatest possible technological benefits in the most cost-efficient manner . . . Further details on the structure of FutureGen will be provided next month."

November 9, 2007 DOE releases Final Environmental Impact Statement (EIS) on 4 potential FutureGen sites; Record of Decision (RoD) on DoE's site selection to be issued no sooner than 30 days after EPA publishes notice of availability of Final EIS in Federal Register.

June 1, 2007 DoE releases Draft Environmental Impact Statement (EIS) on 4 potential FutureGen sites, opening 45-day public comment period.

May 25, 2007 FutureGen Industry Alliance releases initial conceptual design report.

July 21, 2006 FutureGen Alliance announces final 4 site candidates: 1) Mattoon, IL, 2) Tuscola, IL, 3) Jewett, TX, and 4) Odessa, TX; rejected, but qualifying, candidates were 1) Effingham, IL, 2) Marshall, IL, 3) Henderson County, KY, and 4) Tuscarawas County, OH.

May 4, 2006 Host site proposals due; FutureGen Industry Alliance receives 12 proposals. April 7, 2006 Notices of intent to submit proposal due.

March 7, 2006 FutureGen Industry Alliance issues Request for Proposals (RFP) for FutureGen host sites.

March 2, 2006 Indian Prime Minister Manmohan Singh signs agreement making India first foreign nation to join FutureGen government steering committee; South Korea joins later.

December 6, 2005 US Secretary of Energy Bodman signs formal agreement with FutureGen Industry Alliance.

September 13, 2005 Seven founding members establish FutureGen Industry Alliance in partnership with US Department of Energy "to facilitate the design, construction and operation of the world's first near-zero emissions coal-based power plant;" founding members are AEP, BHP, BTU, CNX, FCL, RTP, and SO.

February 27, 2003

President Bush and then-Energy Secretary Spencer Abraham announce FutureGen, $1 billion, 10-year demonstration project for 275-MW prototype coal-fired power plant; plant would combine electricity and hydrogen production while achieving at least 90% carbon capture; simultaneously, US Under Secretary of State for Democracy and Global Affairs Paula Dobriansky announced international climate cooperation initiative, Carbon Sequestration Leadership Forum.

Source: ClearView Energy Partners, LLC, drawing from media and government sources

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RISKS AND DISCLOSURES Risks

Analyst Certifications

Disclosures

(c) 2009 ClearView Energy Partners, LLC. Any reproduction or distribution of this report without the prior written consent of ClearView Energy Partners, LLC is prohibited.

The opinions, forecasts, recommendations, projections and interpretations of macro events contained in this report are those of the analysts preparing this report and are based upon information available to them as of the publication date of this report. The analysts preparing this report based the opinions, forecasts, recommendations, projections and interpretations of macro events contained herein on sources they believe to be accurate and reliable, but completeness and/or accuracy is neither implied nor guaranteed. The opinions, forecasts, recommendations projections and interpretations of macro events contained herein are subject to change without notice. The analysts preparing this report are not registered lobbyists and do not advocate or lobby for any particular policy action on behalf of clients. Although this report may mention specific companies by name and/or specific industries and industry sectors, this report was not prepared, is not intended and should not be interpreted as a research report regarding the equity securities of any company.

I hereby certify that the views expressed in the foregoing research report accurately reflect my personal views as of the date of this report. I further certify that no part of my compensation was, is or will be directly or indirectly related to the specific recommendations or views contained in this research report. By: Kevin D. E. Book I hereby certify that the views expressed in the foregoing research report accurately reflect my personal views as of the date of this report. I further certify that no part of my compensation was, is or will be directly or indirectly related to the specific recommendations or views contained in this research report. By: F. Chase Hutto, III I hereby certify that the views expressed in the foregoing research report accurately reflect my personal views as of the date of this report. I further certify that no part of my compensation was, is or will be directly or indirectly related to the specific recommendations or views contained in this research report. By: Kevin M. Kolevar

Legislative, regulatory and diplomatic agendas are subject to change.