considerations in setting a regional co2 cap n.
Download
Skip this Video
Loading SlideShow in 5 Seconds..
Considerations in Setting a Regional CO2 Cap PowerPoint Presentation
Download Presentation
Considerations in Setting a Regional CO2 Cap

Loading in 2 Seconds...

play fullscreen
1 / 13
emera

Considerations in Setting a Regional CO2 Cap - PowerPoint PPT Presentation

97 Views
Download Presentation
Considerations in Setting a Regional CO2 Cap
An Image/Link below is provided (as is) to download presentation

Download Policy: Content on the Website is provided to you AS IS for your information and personal use and may not be sold / licensed / shared on other websites without getting consent from its author. While downloading, if for some reason you are not able to download a presentation, the publisher may have deleted the file from their server.

- - - - - - - - - - - - - - - - - - - - - - - - - - - E N D - - - - - - - - - - - - - - - - - - - - - - - - - - -
Presentation Transcript

  1. Considerations in Setting a Regional CO2 Cap Mark S. Brownstein Director, Enterprise Strategy RGGI Workshop New York, New York. November 30, 2004

  2. Considerations in Setting a Regional CO2 Cap • Effect on Fuel Diversity: The Northeastern Coal Question • The Effect of Environmental Adders and Natural Gas Price on The Competitiveness of Coal • An Unequal Playing Field: The Effect of An Expanded PJM on the Competitiveness of Coal • Why Functioning Capacity Markets Matter • Allowance Allocation: Equity Matters • Timing: The Case for Sufficient Lead Time

  3. The Dispatch CurveVariable Cost = Clearing Price = Energy Revenue Illustrative Dispatch Curve • Dispatch Curve 101 • Your place in the dispatch curve is typically determined by your variable cost. • Fuel = 75% of your variable cost. • Therefore, fuel cost is a good proxy for your place in the dispatch curve – aka your “dispatch cost.” $ / MWh In PJM, the last unit running sets the market clearing price for all other units running at that time. Load-following coal or combined-cycle natural gas units typically set the market clearing price, with gas setting the market clearing price approximately 50% of the time, with coal setting the market clearing price the remainder of the time.

  4. 7,338 Btu/kWh CCGT with • burner tip gas prices at: • $7.50 • $5.53 • $3.92 Load-Following Coal v. CC Natural Gas in PJMToday Today’s gas price Load-following coal beats combined-cycle natural gas units absent a significant and sustained drop in natural gas price, even in spite of a recent spike in coal prices and emission allowance costs.

  5. Load-Following Coal v. New Natural Gas in PJMTomorrow • 7,338 Btu/kWh CCGT with • burner tip gas price at: Nov-2004 2008 Gas Price $7.20/MMBtu $52.83 Feb-2004 2008 Gas Price $6.00/MMBtu $44.03 Rising environmental compliance costs continue to push load-following coal to the margin, with the future price of natural gas and cost of CO2 compliance emerging as the two wildcards in the viability of load-following coal capacity in the RGGI region.

  6. The Unlevel Playing FieldMerchant v. Regulated/Re-Regulated Generation National Distribution of Merchant Generation OTC Expanded PJM Merchant Generation Ownership* Total U.S. Generation Capacity: Merchant* 43% Utility 36% Public 21% >80% 60% - 80% 40% - 60% * Represents non-utility and non-public power generation ownership Source: PowerDat 20% - 40% <20%

  7. S&P Ratings CriteriaDebt, Cash Flow, and Perceived Business Risk Merchant Generation “Diversified” • Distribution Companies S&P Report 11/23/2004 A trend is emerging where the bond market views competitive markets as inherently risky, rewarding rate-based generation with favorable cost of capital.

  8. Coal in RGGI v. Coal Outside RGGIThe Crux of The Leakage Concern $250M capital investment for a 500MW plant As a consequence of easier access to capital and lack of a CO2 constraint, load-following coal units outside RGGI are set to enjoy, at a minimum, a $13 dispatch cost advantage over similar units in RGGI. Transmission capacity becomes the only limit on this advantage.

  9. Production Cost v. RevenueEarning Enough to Build & Maintain Generation Basic Market Dynamics Capacity Revenue Market Clearing Price DISPATCH COST ($/MWH) Energy Revenue Off Peak Market Clearing Price Energy Revenue Under current market conditions, energy revenues alone are rarely enough to recover the full cost of new investment making the degree of capacity payments critical to the viability of new investment.

  10. Fossil MWh (lbs/MWh) Gross Product (lbs/$) Total MWh (lbs/MWh) Heat Input (lbs/mmBtu) Population (tons/person) 2,500 1,500 200 10 0.6 1,322 180 9 0.5 1,868 158 0.5 2,000 8 150 1,482 1,000 0.4 821 1,500 6 100 0.3 1,000 4 3.2 500 0.2 0.15 50 500 2 0.1 RGGI U.S. RGGI U.S. RGGI U.S. RGGI U.S. RGGI U.S. Emission Allocation as National Precedent Setting Rules That Work for the Region National CO2 allocations based on an emission performance standard concept favor the RGGI region.

  11. 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% NJ BGS Auction StructureFixed Price for Consumers = Margin Risk for Generators The NJ auction accounts for approximately 21% of the total load in RGGI. It is successful in stabilizing prices for consumers, forcing wholesale generators to compete on price. HEP NJ Avg. Rate $61.52/MW-day HEP HEP HEP BGS Fixed Price (12 Month) NJ Avg. Rate 5.48 c/KWh BGS Fixed Price 36 Month through 8/08 Fixed Price Contract 4.4 c/KWh BGS Fixed Price (10-Month) NJ Avg. Rate 5.27 c/KWh 1 AuctionFor all Load NJ Avg. Rate 5.06 c/KWh BGS Fixed Price (36 Month) NJ Avg. Rate 5.52 c/KWh BGS Load BGS Fixed Price (34-Month) NJ Avg. Rate 5.56 c/KWh BGS Fixed Price 36 Month through 8/09 2006 2002 2007 2003 2004 2005

  12. PSEG Power Term Contracts 100 Generation output not under contract 90 80 70 Other term energy contracts 60 2003 BGS (10 Month) % of Power Generation 50 2004 BGS 40 2004 BGS (36 Month) (12 Month) 30 2003 BGS (34 Month) 20 10 United Illuminating 2004 2005 2006 2007 2008 Case Study: PSEG PowerBGS and Long-term Contracts Through 2008

  13. Key Takeaways • The Future Price of Natural Gas Matters. Rising natural gas prices improve energy margins for coal and nuclear, but also raise electricity prices for consumers. Declining natural gas prices eat into margins for nuclear and coal, potentially forcing some coal to retire. • The Price of CO2 Matters. Given current coal and natural gas price trends, a carbon cap that drives CO2 prices above $10 a ton has a high probability of forcing RGGI region coal capacity to close. • Market Rules Matter. Return on capital is a function of energy and capacity revenues. Currently, energy margins are inadequate to fully recover the cost of capital in new or modified plant, making capacity payments critical to the viability of investment in environmental retrofits and new generation. • A Level Regulatory Playing-Field Matters. Companies with the ability to recover the capital cost of emission control equipment through rates enjoy a competitive advantage over those that do not. Companies required to internalize the cost of CO2 or other environmental adders are penalized in competition with those that do not face such restrictions. This is the looming reality of an expanded PJM. • Timing Matters. In an effort to demonstrate positive and certain cash-flows, companies are entering into long-term contracts today, making future CO2 regulation a potential threat to their expected energy margin.