Back when QF contracts were being ground down to nubs by utilities, independent generators called it a ?year-11 cliff.? That was because payments were abruptly reduced after 10 years under most standard-offer contracts. With a somewhat new crop of private generators in the current market, there?s a different year-11 cliff. This time it is the year 2011, which is when the number of contracts with the Department of Water Resources (DWR) will fall dramatically. In 2011 alone, 4,640 MW worth of state contracts will expire. This year marks the peak of the state?s contract portfolio at 12,660 MW, according to DWR. That means that in 2004, about 20 to 25 percent of the state?s total capacity is under DWR contract. In 2012-13, that number drops to 220 MW and then disappears. The wallop to the supply system from losing that much contract power is supposed to be assuaged by the state?s commitment to resource adequacy. That presumably will enable new power plants to be built at competitive prices by privately owned generators, investor-owned utilities, or both. New plants may be up and running in the 2007 to 2010 time frame, but the lack of state or utility commitment puts investments in plants on hold. Thus, new supplies, and especially efficient replacement supplies, look to be mighty thin in the short term. In the intervening years?2004 to 2010?contract expirations will account for 11,290 MW. Some of the juice comes from power plants in the state. Plant owners will either have to replace the state contracts with utility pacts or wing it?trying to sell energy in the merchant market. Other supplies under contract come from megawatts obtained by traders in the market and don?t represent new or specific supplies. In those cases, traders could well be relieved of the obligation to provide on contract specs as the trading market never developed to the liquid level that most expected. The contracts were signed in the heat of the energy crisis. A desperate state was watching utilities begin to topple and blackouts reverberating into an economic shakedown, on top of high wholesale prices. But marketers and generators who signed the contracts were almost equally desperate as they could see the bright, profitable future exploding in the midst of volatility and profit taking. Now, the chance for profits on contracted energy has narrowed?especially as fossil-fuel prices rise. Forty percent of energy in DWR contracts this year?up to 70 percent in 2011?is tied to the price of natural gas fuel. Because the amount of renewables in the state?s contracts is negligible, that means that more than half of the contracts depend on spark spread?the difference between the cost of producing power and its price?and trader acumen for profitability. The contracts that are tied to power plants are golden. They are a low-risk opportunity for private generators to pay off bankers for building or buying the plants. According to DWR, the certainty of state contracts caused 36 new power plants to be built for more than 5,000 MW. However, contracts are good only for the duration of the deal and there are no more state contracts to be had. Basically, there are no new contracts for fossil-fuel plants in the pipeline as utilities that took over from the emergency state procurement have little interest in contracting for power plants that they don?t ultimately own. With the drop-off in contracts, the shape of supplies is changing?for the better. Under many contracts, the market is flooded with power at 6 a.m. A total of 1,725 MW are under contract for power deliveries that start at 6 a.m. and stop at 10 p.m. In the past, the grid operator had trouble managing the flood of morning megawatts, but apparently this year, particularly this summer, the California Independent System Operator is having less of a problem using that power. When CAISO can?t use it, it?s a waste of money, as those megawatts go into the ?dec market.? It is a chance for generators who signed those contracts to make more; however, because it?s in the dec market, generators get paid for backing off their plants. A silver lining to state contract expiration is that as agreements expire, the grid operator has more of a chance to shape supplies to load so that power is more economical. Currently, the grid operator has little chance to shape economical supplies with one-quarter of the state?s supplies in contracts. Of that, only 12 percent is in dispatchable power this year?and that doesn?t change much over time until 2011. Although many companies have decimated their trading arms, neither traders nor DWR seem concerned, at least in public, about meeting contract terms. One company, Allegheny, sold its contract to Goldman Sachs and extricated itself entirely from California. While I?m not privy to profits or losses for those holding state contracts, I can see that they can?t be making much of a killing these days. The entire portfolio last year averaged 3.8 cents\/kWh. The state is happy to be done with making deals?and nearly done with renegotiating and administering contracts. ?We want to go back to a water company, and to having utilities meet customer demands,? said DWR spokesperson Oscar Hidalgo. With contracts unavailable from the state, the California Public Utilities Commission is supposed to take over the role of doling out prize deals for power at ?competitive? prices. The last contract executed by the state was in September 2001. That?s nearly a three-year gap. The commission has approved only one utility ?contract? in the meantime?an odd duck of a deal between Edison and an unregulated affiliate for the Mountainview plant. To keep supplies from falling lemming-like over the year-11 cliff, all eyes are on the CPUC. <b>Contract Details<\/b> <b>2004<\/b> West Coast Power (Dynegy and NRG): 200 MW of seven-days-a-week, 24-hours-a-day (7\/24) contracts and another 600 MW for Monday-through-Saturday, 6 a.m. to 10 p.m. power (6\/16). This is south of Path 15 (SP15) and must-take-or-pay power. There are also contracts for off-peak blocks of power between 200 MW and 1,500 MW. <b>2005<\/b> Calpine: 180 MW of NP15 dispatchable power from its San Jose plant. El Paso: 50 MW of NP15 and another 50 MW of SP15 6\/16 must-take power. Morgan Stanley: 35 MW of SP15 7\/24 must-take power. <b>2007<\/b> Williams: 450 MW of SP15 6\/16 must-take power. <b>2009<\/b> Calpine: 1,000 MW of NP 15 7\/24 must-take power from its own power plants and 1,000 MW of NP15 7\/24 must-take power, not plant-specific. <b>2010<\/b> Colton: 80 MW peaker. Williams: 325 MW of SP15 6\/16 must-take and another 1,045 MW of SP 15 dispatchable. <b>2011<\/b> Calpeak: 242 MW of both NP15 and SP15 dispatchable energy from six peaking plants. Calpine: 495 MW of NP15 dispatchable, tied to power plant output. Goldman Sachs: 800 MW of SP15 7\/24. GWF: 164 MW from Tracy peakers. High Desert: Between 730 MW and 840 MW SP15 dispatchable, tied to plant. Wellhead: 50 MW peaker, dispatchable. Sempra: 1,200 MW (seasonally 800 MW) of SP15 7\/24 must-take with some 6\/16 some years, supposed to be tied to Otay Mesa. PacifiCorp: 300 MW of NP15 6\/16, dispatchable and must-take.