I have reviewed the recent study by Public Policy Consulting entitled, The Impact of a Renewable Energy Portfolio Standard on Retail Rates in Colorado. It caught my eye because (1) it concludes that adopting a renewable portfolio standard would save ratepayers money (My bill's analysis had come to the exact opposite conclusion), (2) it was distributed widely that it was being used as far away as Michigan to support their efforts for a RPS and (3) the study will likely be used as a justification for the need for more wind projects by arguing wind is cheaper than natural gas alternatives.
Given our different conclusions, I decided to evaluate why our studies disagreed.
If renewables were indeed less expensive than conventional alternatives as suggested by the Public Policy Consulting Report, why mandate their purchase and set a minimum market share? Colorado does have a voluntary wind power purchase program called Windsource that Xcel ratepayers can elect to participate in. Unfortunately for wind proponents, the program found that only 0.5% of their customer load was willing to pay the program's 2.5c/kWh premium needed to recover the higher power costs. Through adoption of the renewable portfolio standard (RPS), the House Bill would effectively force the remaining 99.5% of the Xcel customer load and 100% of the Aquila Energy load with no choice but to pay for the higher cost renewable power. If bill proponents are correct about the economics, they should push the Colorado PUC to reset the Windsource program costs accordingly and check out the customer response. No new legislation would be required. Bottom line, bill proponents want a RPS because they did not like the outcome of voluntary green power purchase programs. Wind proponents realize that they are unable to compete against conventional power sources unless the utility is forced to purchase from uneconomic power sources.
The true cost of a renewable portfolio standard is highly sensitive to input assumptions on future natural gas prices, extension of the production tax credit, wind production costs (capacity factor, O&M) and the accounting for transmission upgrading cost. For example, if the expired production tax credit is not extended, the net present value of the Colorado renewable portfolio standard shifts from offering a savings ($56 million) to a net higher cost (-$1.4 million). The study assigns an 80% probability that the PTC will be extended. If the PTC is not extended, Xcel's and Aquila's Colorado ratepayers would need to make-up for the difference under HB1273.
Future natural gas prices are an important assumption since they affect production costs for 20% of the 2001 in-state Colorado generation that are the most vulnerable to being displaced by renewable power mandates. I share a similar conclusion that gas generation was on the margin most of the time. The study assigns a 50% probability that natural gas prices will be $0.50/MMBtu higher than the DOE Annual Energy Outlook 2004 to resolve a "bias" while assigning only a 20% probability to gas prices being $0.50/MMBtu lower. Overall, this works out to a weighted average price of $0.15/MMBtu higher gas price forecast.
The report concludes that additional wind power would be built to meet the target--I agree. Wind production costs in the Colorado study were based upon wind projects being located in class 4 wind resource areas and achieving a 35% capacity factor in 2003 and increasing to 40% by 2023.
•These areas in Colorado are mostly limited to areas in the Southeastern and Northeastern corners of the state making transmission upgrades and losses an important issue. At spacing of 1 turbine per 40 acres, a total of 75 square miles of land area would be required to meet the 1,800 MW 2020 renewable capacity target.
•The 35% wind capacity factor assumption is well above the current average capacity factor for the 2 existing Colorado wind farms (25.9%). If actual capacity factors are used in the calculation, wind production costs would initially be roughly 35% higher and could increase to 50% higher if technology improvements are unable to reach the DOE technology target performance. To achieve higher performance factors, developers may pursue projects at some mountain peaks where wind conditions are better but where siting problems and opposition maybe greater.
•The Colorado study also assumes that wind capital costs will decline by over 35% from today's level to reach $750/kW by 2023 with advances in wind turbine technology. If technology costs do not decline as assumed, wind production costs would remain at existing high non-competitive cost levels and the cost of adopting the RPS would be higher.
The study is correct on some findings--less water would be required and lower CO2 emissions. However, my estimates would be less than shown in the report given its use if an overly-optimistic high wind generation capacity factor assumption.
As you are well aware, a study is only as good as the input assumptions made. Its conclusions are not necessarily transferable to other states. I have little doubt that wind proponents will push hard in areas that gas is on the margin and wind resources are good.