Utility Owned Generation Why It Makes Sense Restructuring Roundtable Boston, MA December 8, 2006 Lisa Thibdaue

Electricity Policy Choices Promises of restructuring and competitive generation Lower energy prices New, clean generators will be built Risks will be shifted from customers to competitive suppliers’ shareholders Those promises have turned out to be myth in practice Costs of power supply have doubled for customers, and have become more volatile Risks are being shifted back to customers from competitive supplier shareholders, even for newer plants, with RMR contracts No new generators are being built, and now the generators want long term contracts to do so (shifting the risks back on customers) New market rules are going to pay existing generators more

Energy Markets Operate under a “Highest Bid Clearing Price” Methodology In the ISO-NE Energy market, all generators bid on a hourly basis for the following day. ISO ranks the bids lowest price to highest price. The last generator needed to serve the load sets the price which is then paid to all generators bidding below that price. Example: Load is 500 MW Generator A bids 150 MW at 4 cents Generator B bids 100 MW at 6 cents Generator C bids 200 MW at 6.5 cents Generator D bids 100 MW at 10 cents Generator E bids 100 MW at 12 cents ISO accepts bids from Generators A, B, C, and D. All get paid 10 cents – the price bid by the last unit (Unit D) necessary to meet load. Hourly Load 14 12 Clearing Price 10 Unit A 8 Unit B Unit C 6 Unit D 4 Unit E 2 0 100 200 300 400 500 600 Only about 15-25% of the energy in New England is transacted through this spot market—the other 75-85% of energy is addressed through bilateral contracts from supply aggregators and utilities. Generators and supply aggregators recognize how the spot market works, and they predict how its prices will change over time, especially related to the cost of natural gas. They translate these predictions into what they are willing to bid to supply in a Basic Service bilateral contract.

Realities of Competitive Generation The sole obligation and responsibility of competitive generators is to their shareholders. Competitive Generators make money based on the capacity, energy and other products they sell into the market. All revenues beyond their actual costs go to the benefit of shareholders in the form of profits—not to customers as lower rates. The profit motive could cause a generator owning multiple plants to configure its bidding strategy to drive the overall market clearing prices up so even cheaper plants get paid higher prices. The profit motive could also cause an intermediate or peaking generator to force ISO to purchase from it for longer that ISO actually needs that type of power. Example: ISO needs 50 MW of peaking capacity between 1:00 PM and 4:00 PM. The peaking generators claims that it can only operate for a minimum of 10 hours, thus forcing ISO to pay for 10 hours when it only needs 3 hours from that generator. A competitive generator may have no incentive to build new units if it believes that will drive overall capacity or energy market prices down. Competitive generators are free to shut down individual plants based on their economics and strategic decisions of their parent companies and shareholders. Example--Load is 500 MW Generator A (owned by XYZ Corp) generates 100MW at a cost of 4 cents Generator B generates 100MW at a cost of 4 cents Generator C generates 100 MW at a cost of 5 cents Generator D (owned by XYZ Corp) generates 100 MW at a cost of 5 cents Generator E generates 100 MW at a cost of 5 cents. Generators A, B, C and E bid at their costs. Generator D (owned by XYZ Corp) gambles that ISO needs its generation, and bids 5.2 cents. All generators get paid 5.2 cents, increasing profits by 0.2 cents for all generators, including XYZ Corp’s other generator A.. XYZ Corp pre-tax profits increase by $17 mil (if units run 50% of the time)—Customer bills go up 4%.

The Market has not Met New England Needs In areas without the right mix of generation, other types of generation are called upon to fill the need--this is not economic. In CT, intermediate plants are currently being utilized as peaking plants. This creates additional costs for customers. Even though inefficient generators were supposed to be allowed to fail, ISO cannot let them fail due to the tight capacity situation, and we will always be obligated to keep them on line until sufficient capacity is built. CT customers have paid nearly $ ½ billion in RMR payments (2004-2006) MA customers currently are paying $358 million in annual gross fixed rev. req. for RMR arrangements. Will the new FCM cause new baseload to be built?

Long-term Capacity Contracts are not the Answer Contracts shift risk back to customers Contracts can degrade a utility’s balance sheet and financial condition Customers are still paying stranded costs associated with PURPA and IPP contracts CL&P customers have paid $3 billion in over market costs Contracts could be part of an overall utility supply plan.

Utility Owned Generation Motivates Different Behaviors A utility-owned plant will operate in a manner that allows it to create savings on behalf of customers. In order to break the connection between the market clearing price and standard offer pricing, the “bid stack” must be broken – in other words, customers need access to electricity that is priced separately from the ISO market mechanism. A utility’s profits on generation come in the form of an authorized return on equity on the actual capital invested in the generating plant. State-regulated, utility returns are typically much less (10-11%, and capped) than those required by competitive entities (15-20%). Customers pay for the investment and for the actual operating and fuel costs of the plant. No profit is paid on utility operating costs or fuel. The utility will bid its plants into ISO at cost--it has no motivation to bid otherwise. The utility has no motivation to let demand outpace supply. In fact, just the opposite is true – the utility’s obligation to its customers and its regulators aligns its motivations with its customers. Competitive Generator Utility Generator - Cost to generate a kwh is 5 cents - Cost to generate a kwh is 5 cents - Highest Bid Clearing Price is 9 cents - Highest bid price is 9 cents - Customers pay 9 cents - Customers pay 5 cents - Generator keeps 4 cents as added profit - Customers avoid paying 4 cents

A Utility Can Operate Generating Plants Just as Efficiently as a Competitive Owner In 42 states, the regulated utility still owns generation Some restructured states have reversed initial positions on utility ownership of generation Operating and Availability metrics overseen by state regulators will assure that the plant is operating at the highest level. The utility will be penalized if it is not. Public Service Company of New Hampshire owns 1150 MW of fossil/hydro generation, which it uses to serve approximately 70% of its energy requirements. PSNH’s plant output has increased every year since 2001. PSNH generation’s availability during the highest price market days over the last four years has averaged 95%. Several PSNH units have set all time high production output and capacity factors since deregulation in 2001. The January 2007 energy component of PSNH’s residential bill is 8.59 cents compared to 11.41 cents for CL&P. For a typical residential customer who uses 700 kWh/month this extra 2.8 cents is worth $19.74/month or $237 a year. Furthermore, New Hampshire customers do not pay RMR charges.

Benefits of Utility Owned DG Customers are more receptive to partnering with local utility Ease of transaction, since service could be done through tariff or facilities charge Utility can control facility to coordinate with other resources to minimize all customer costs Customers have recourse to the regulators on issues relating to utility owned generation Lower cost financing could provide economic benefits and opportunities to install renewable energy systems.

The Proof is in the Pudding

To Close…. We are not advocating a return to fully integrated, monopoly utilities We suggest merely adding other choices to the supply portfolio that are geared to providing value for customers.

Appendix What Are the Major Generating Companies in CT? Company Headquarters CT Generation RMR Contract Dominion Richmond, VA Millstone – 2,037 MW No NRG Princeton, NJ Norwalk Harbor, Devon, Middletown, Montville, Cos Cob – 1780 MW Yes, for plants in red PPL Allentown, PA Wallingford * – 216 MW Yes, even though plant came on line in 2001 PSEG Newark, NJ Bridgeport Harbor, Exeter, New Haven Harbor – 985 MW Merrill Lynch New York, NY Milford Power * – 492 MW Yes, even though plant came on line in 2004 Duke Charlotte, NC Bridgeport Energy * – 447 MW Yes, even though plant came on line in 1998 Total – 5,957 MW (85% of Total CT Generation) Red indicates RMR contracts in place – total of $335 million annually for CT (before energy credits). * Indicates plants constructed since restructuring.