California to save $3.5 billion on renegotiated power contracts

SAN FRANCISCO, Calif., April 23, 2002 — State officials Monday announced that they have restructured eight of California’s long-term energy contracts, reducing costs by approximately $3.5 billion (from approximately $15 billion to $11.4 billion, or 23 percent) and providing the state with stronger commitments for needed new power plants, greater flexibility in utilizing the power, and competitively-priced electricity that will be delivered during summer peak periods.

Governor Gray Davis, the Public Utilities Commission, Department of Water Resources, and the Electricity Oversight Board said the new deals for four contracts with San Jose-based Calpine Corporation and one with High Desert Power Plant LLC, a subsidiary of Baltimore, Md.-based Constellation Energy Corporation, along with three contracts with renewable energy providers – Capitol Power, Cabazon, and Whitewater Hill – were the result of negotiations that began in late Fall. In separate action, Calpine and Constellation agreed to settlements of all claims with Attorney General Bill Lockyer for alleged electricity- pricing violations.

The new contracts represent the first successful renegotiations of power pacts originally signed by the State in the Winter and Spring of 2001. The long-term contracts, along with record conservation, the construction of 11 new power plants approved by the Davis Administration, and long-overdue action by the Federal Energy Regulatory Commission (FERC) to cap wholesale prices, were largely responsible for breaking the back of the spot market, which led to lower electricity prices and eased the state’s power crisis last summer.

“This was a team effort by all parties and I congratulate our negotiating team,” said Gov. Davis in announcing the agreements. “They brought back a better product for less money. The State has gotten the power it needs, where it needs it, when it needs it and at a more competitive rate.

“We had three goals in restructuring these contracts: to reduce costs, to insure reliable sources of new power, and tailor the delivery of power to meet the state’s needs,” continued Gov. Davis “The State has achieved each of these goals and kept renewable energy as a key part of its power portfolio.”

“But these new contracts do not mean that FERC should shirk its responsibility to California. Californians are still owed billions of dollars in refunds. Allegations of market manipulation need to be thoroughly investigated in a timely fashion. And for the remaining generators that refuse to renegotiate contracts signed when the markets were dysfunctional, we’ll see them in court and at FERC.”

With Calpine, state negotiators sliced the state’s longest contract from 20 years to 10 years with at least $800 million in savings. Two other 10-year baseload energy contracts were reduced by two years, with savings of nearly $1.03 and $1.16 billion, respectively.

Calpine executive vice president and COO Jim Macias said Calpine was very pleased with the negotiations. “These restructured agreements resolve questions and uncertainty surrounding our contracts. The state is assured electricity will be available under more flexible terms when supplies will be critically needed. Calpine continues to benefit from solid, long-term power contracts and increased revenue and cash flow in the early years.”

The agreement with Constellation Energy will result in savings of at least $560 million off the original $3.28 billion contract. The agreement also reduces the eight-year, three-month contract by six months.

State officials explained that aside from cost savings for ratepayers, the new contracts provide stronger provisions to bring new power plants online as well as more favorable terms for delivering the power. Many of the State Auditor’s recommendations were also incorporated in the new pacts.

For example, the new contracts provide incentives to complete plans for new power plants, provide the state with the right to inspect those plants, give DWR more flexibility and reliability in obtaining power, allow it greater freedom to tailor its power supply to meet demand, and require the companies to pay DWR the costs of purchasing replacement energy if contract power cannot be delivered. They also require the delivery of power to Northern California (north of Path-15) to alleviate power shortages in the Bay Area. The new contracts also improve DWR’s ability to assign contracts to the state’s investor-owned utilities when they achieve investment-grade credit ratings.

In the enforcement settlements with the Attorney General, Calpine agreed to pay $6 million and Constellation $2.5 million to the state. The settlements end the Attorney General’s claims against the two power companies regarding improper electricity pricing practices and the seeking of refunds from FERC for the allegedly illegal electricity rates charged in California. Calpine will put $1.5 million of the settlement proceeds into a fund established by the Attorney General for retrofitting public facilities with solar power. Constellation’s payment to the solar power fund will be $1.25 million.

In addition, because of the benefit to California ratepayers, the California Public Utilities Commission has also agreed to drop its FERC proceeding against Calpine and Constellation.


* DWR has four contracts with Calpine. Two provide baseload power (#1 and #2). Two others (#3 and #4) provide peaking power that can be tailored to meet hourly and daily changes in consumer demand.
* Contracts #2, #3, and #4 have new provisions to insure new power plants are built. Calpine will suffer penalties if they are not constructed.
* Contract #2 requires Calpine to build four plants: Metcalf, Otay Mesa, East Altamont, and one other (to be chosen by DWR among Teayawa, Inland Empire, and San Joaquin Valley Energy Center). If Calpine does not meet certain requirements, the State may takeover the site and permit from Calpine and complete the plant itself.
* Powerful incentives to build new plants have been added in Contract #3. This contract requires Calpine to build 11 peakers; four are already built. If it does not build the other seven by June 1, 2003, the capacity payments it can charge for those units over the life of the contract will be reduced by approximately 30 percent. If it fails to build a unit by December 31, 2003, it loses the right to sell power from that unit to DWR, and it may not substitute power.
* Contract #4 requires Calpine to build a plant in San Jose. If it does not do so, DWR may terminate the contract.
* Capacity payments are tied to the actual availability of capacity in Contracts #3 and #4. Calpine will guarantee an availability factor of 98 percent in summer and 92 percent in winter, with pro rate reductions of the capacity payment if those targets are missed and with incentives for Calpine to exceed those targets. Payments also will be reduced if annual performance tests show lower than expected capacity, and if the plant’s ability to deliver is limited by permit restrictions.
* DWR will be paid damages (the cost to DWR to purchase replacement energy in the market) for an unexcused failure to deliver power.
* DWR will receive better utilization of power as part of the new contracts as part of a new provision that says Calpine may not supply from ISO’s imbalance energy market unless DWR or ISO directs the company do to so.
* Contract #2 will require power to be delivered into Northern California, north of NP-15. The original contract allowed Calpine to deliver power from its own plants into either SP-15 or NP-15.
* Contract #2 will limit Calpine’s ability to substitute power by requiring it to provide power into NP-15 when its energy suppliers are tight.
* New provisions in Contracts #3 and #4 limit Calpine’s right to substitute energy.
* New provisions redefine “Force Majeure,” limiting the company’s ability to failure to delivery energy.
* New “anti-gaming” provisions in Contracts #3 and #4 include new, stronger penalties (including rights to terminate the contract) for certain inappropriate uses of the imbalance market.


* All four contracts have been tailored to provide DWR with flexibility in utilizing power. Under the old contracts, DWR had limited ability to tailor when the energy was needed.
* Contracts #1 and #2 have new provisions that allow DWR to acquire additional dispatchable power for 2002 and 2003 at better prices and allow for day-ahead scheduling of power, with up to 30 percent scheduled intra-day.
* Contract #3 is reduced from the fixed price of $73/MWh to a tolling agreement based on an indexed gas price and a guaranteed heat rate of 10.5 MMBTU/MWh. (At today’s gas prices, the price falls from $73 to $45 MWh.)
* Contract #3 gives DWR enhanced dispatchability rights (30-minute dispatch for all contract hours).
* Contract #4 gets additional flexibility to tailor its power. It now can schedule 4,000 hours of energy on a day-ahead or hour-ahead basis. Up to 2,000 hours can be scheduled on less than an hour-ahead
basis. Under certain circumstances, up to 1,000 hours can be scheduled on as little as 15 minutes notice.

* Both Contracts #1 and #2 are cut from 10 to 8 years. Payments in the two canceled years would have totaled over $1 billion in each contract.
* Contract #2 is cut from $61/MWh to $59.60 MWh, saving approximately $80 million.
* Contract #3 is cut from 20 years to 10 years, saving $800 million in capacity payments. It also saves energy payments that would have been made in years 11 through 20. (The amount of this saving depends on how much energy would have been purchased in years 11-20.)
* Contract #3 is reduced from a fixed energy price of $73/MWh to a tolling agreement, based on an indexed gas price and guaranteed heat rate. Based on the allowed hours of dispatch under the contract, this change could save up to $280 million during the shortened life of the contract.
* Under Contract #3, Calpine must complete construction of the peaking units by June 1, 2003. If it doesn’t, capacity payments are reduced. Units that do not come on line by December 31, 2003 are eliminated from the contract. Each unit eliminated reduces DWR costs by $65 million.
* Contract #4 reduces costs by denying Calpine the right to sell substitute energy prior to the time it brings the plant online, saving DWR approximately $12 million this year.


The California Department of Water Resources (DWR) has an eight-year, three-month contract with Constellation subsidiary High Desert Power Plant, LLC, which has been reduced by six months.

* Under the old contract, High Desert could provide substitute energy to the State before completing construction. There is now a strong incentive for High Desert to complete construction by the July 1, 2003 estimated completion date because the State will not make any capacity payments until the plant has been brought on line and its capacity established. Further, High Desert is not allowed to provide substitute energy until the plant has been completed, and then only if the plant is unable to operate.
* If High Desert ceases construction efforts by October 2004, DWR may terminate the contract and collect a $50 million payment from High Desert, guaranteed by Constellation.
* The revised contract gives DWR the exclusive right to all the output from the High Desert plant. High Desert may not sell to any third parties once the contract begins. In addition, High Desert must deliver all energy requested by DWR from the plant, unless the plant is unable to generate the energy because of an outage, repairs, permit or plant limitations, or other similar events.
* If High Desert fails to deliver energy without a proper excuse, the contract can be terminated. DWR can also impose a $7.5 million liquidated damages penalty if High Desert fails to deliver from the plant for economic reasons (for example, if it decides it would be cheaper not to run the plant).
* There will also be annual capacity testing to ensure that the plant is running at optimum output. To the extent it is not, the monthly capacity payment is reduced.
* There is also a 95 percent availability guarantee – to the extent High Desert does not provide DWR with scheduled energy 95 percent of the time, the monthly capacity payment is reduced by a proportional percentage (i.e., if High Desert provides only 90 percent of the energy DWR schedules, the capacity payment is reduced by five percent).
* High Desert may not supply from ISO’s imbalance energy market unless DWR or CAISO directs it to do so. Use of the imbalance energy market is restricted to hourly variations and daily curtailments of plant output. This insures that DWR is getting better utilization of the State’s energy resources.
* DWR also obtains an additional 400 MW of power during May to October 2002 and 2003 (prior to the time the plant is brought on line).

* Under the old contract, DWR had no ability to shape the energy and was obligated to pay $58/MWW. DWR can now tailor the way it dispatches the unit within the unit’s reasonable operational capabilities. This will allow DWR to utilize the resource to follow load over the course of each day.
* DWR must schedule on a day ahead basis but may on an intraday basis adjust the schedule as circumstances require. Because the High Desert plant is now reserved exclusively for DWR’s needs, only the plant’s actual physical limitations will narrow this flexibility.

* The High Desert contract has been shortened by six months, resulting in savings of roughly $155 million in energy purchases DWR would otherwise be obliged to make.
* The contract price has changed from a fixed energy price of $58/MWH to a fixed capacity payment and an energy price based on actual fuel costs and the plant’s heat rate. This should decrease the average price by more than 15 percent.
* Because DWR will no longer by required to take energy around the clock in amounts unrelated to its needs, it will realize savings of roughly $405 million, making the total savings from the original $3.28 million contract approximately $560 million.
* DWR’s ability to bid the High Desert facility into the CAISO ancillary services markets may result in net revenues to DWR.


* The original contract value was $52,625,000 over five years. ($89/MWh) from a 15 MW biomass plant in Amador County.
* The new contract value is $46,298,000 – a 12 percent reduction. The renegotiated contract reduces the term by six months, lowers the price by $2/MWh and caps the total net income the generator will receive.
* The amended contract contains many of the terms recommended by the State Auditor.
* If the costs of running the plant are lower than projected, then the cost to DWR will be reduced. The amended contract contains many of the terms recommended by the State Auditor.
* In addition to helping insure DWR’s portfolio has renewable power, Capitol now has additional time to bring the plant on-line; extending the operating date from December 15, 2001 to July 15, 2002.


* This 42.9 MW wind contract for 12 years was originally priced at $60/MWh for 12 years. The amended contract reduces that price to either $54/MWh if the units are operating by August 31, 2002 or $40/MWh if the units are operating after August 31, 2002. It also shortens the contract by six months.
* Based on price and length, DWR estimates the renegotiated contract will save between $11.2 million and $29.3 million – a savings of between 14 and 36 percent. The amended contract includes many of the terms recommended by the State Auditor.
* To help insure that DWR’s portfolio has renewable power, Cabazon is given additional time to bring its power online. It extends the Commercial Operation Date from a target date of December 31, 2001 to a firm date of December 31, 2002.


* This 12-year, 65.1 MW wind contract was originally priced at $60/MWh. The amended contract reduces that price to either $54/MWh if the units are online by August 31, 2002 or $40/MWh if the units aren’t running by then. It also shortens the contract by six months.
* The renegotiated contract will save between $17 million and $44.5 million. That’s a savings of between 14 and 36 percent.
* To broaden DWR’s portfolio of renewable power, Whitewater Hill is given additional time to bring its power on-line. It extends the Commercial Operation Date from a target date of December 31, 2001 to a firm date of December 1, 2002.
For copies of the renegotiated contracts, visit “” target=”_new”>

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