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ML&P challenges cost of wind power Utility states its position on the purchase of Fire Island power, with price and service expectations widely different from CIRI’s Alan Bailey Petroleum News
The war of words over the viability or otherwise of Cook Inlet Region Inc.’s proposed 52.8-megawatt wind farm on Fire Island, offshore Anchorage, Alaska, has taken a new twist with a statement by Anchorage power utility Municipal Light & Power on its expectations for any purchase agreement for Fire Island power.
And from that statement, made in a March 30 letter to CIRI from Johnny Gibbons, chairman ML&P board of directors, and James Posey, ML&P general manager, it is clear that CIRI’s and ML&P’s positions on a possible Fire Island power purchase agreement are a long way apart.
“If CIRI, or any other entity, is able to offer renewable energy to ML&P at prices that will ensure electric rate savings for ML&P’s customers (or at least ensure that ML&P’s customers will not pay higher electric rates as a result of the purchase), ML&P is very interested in pursuing such purchases,” Gibbons and Posey wrote. “However, the term sheets that CIRI has provided thus far do not meet those fundamental requirements and are inconsistent with ML&P’s obligation to protect the interests of its customers.”
During a March 31 press conference Posey said that many ML&P customers are on modest incomes and are very sensitive to any rise in power costs.
Needs purchase agreements CIRI wants to bring its planned wind farm online in 2012, to qualify for a federal renewable energy grant of $43.9 million, a grant that would knock a sizable dent in the project cost and hence reduce the cost of power from the facility. But, to finance construction of the Fire Island facility in time to meet the 2012 deadline, CIRI urgently needs power purchase agreements with electric utilities such as ML&P. And, so far, those purchase agreements have not been forthcoming.
On Feb.1 the Anchorage Municipal Assembly passed a resolution urging ML&P, which is owned by the municipality, to negotiate a Fire Island power purchase agreement.
ML&P currently obtains the bulk of its power from gas fired power stations, using natural gas from Cook Inlet gas fields, but with some power coming from a hydropower system at Bradley Lake on the Kenai Peninsula. The utility obtains much of its gas from its share of the Beluga gas field on the west side of the Cook Inlet — ML&P co-owns the Beluga field with ConocoPhillips and Chevron.
However, ML&P also purchases gas from Cook Inlet gas producers.
In February Suzanne Gibson, CIRI senior director of energy, told the Alaska Geological Society that CIRI anticipates delivering power from Fire Island at a cost of about $87 per megawatt hour, with that cost maintained level over a term of 25 years once the wind farm goes into operation (essentially the power cost would represent the amortized cost of the facility plus the facility’s operations and maintenance costs).
Avoided costs In their March 30 letter, Gibbons and Posey provided a projection of ML&P’s avoided energy cost from 2013 to 2035, were the utility to displace some of its current power generation by accepting power from Fire Island. The avoided cost estimates range from $30.20 per megawatt hour in 2013 to $183.01 per megawatt hour in 2037. And with the avoided cost apparently not exceeding the estimated cost of Fire Island power until 2023, the Fire Island power would not seem to meet ML&P’s stipulation of not increasing ML&P’s rates to its customers.
But CIRI questions ML&P’s avoided cost estimates and the data that the utility has incorporated into those estimates.
“The real problem is how do you define what an avoided cost is, because there are all sorts of different ways to do it,” CIRI spokesman Jim Jager told Petroleum News on April 4.
A tariff sheet that ML&P published in November shows the utility’s average cost of power, from all of its power sources, to be $48.72 per megawatt hour, Jager pointed out. That average rate encapsulates a variety of power sources, each with a different power cost, including the relatively low cost power from Bradley Lake as well as the more expensive gas that ML&P would surely replace, were Fire Island power available, he said.
CIRI’s projected cost of power would be more than ML&P’s current average cost of power but less than the utility’s most expensive power, with the wind farm power cost remaining constant over time, Jager said. And the Fire Island power would form a relatively small percentage of ML&P’s total power supply, he said.
During the March 31 press conference Posey characterized ML&P’s March 30 letter as “the first phase of a negotiation” and said that ML&P had calculated its avoided cost estimates using a standard Federal Energy Regulatory Commission formula, a formula also used by the Regulatory Commission of Alaska when reviewing utility tariffs. Essentially, the avoided cost would be the cost of the natural gas that ML&P would have to burn were the Fire Island power not to be available, but would not include the depreciated cost of the power generation plant, Posey said.
“It is a somewhat complicated calculation but it is one you make in accordance with the law and regulations,” Posey said.
Integration costs With the power output from a wind farm varying continuously as the wind strength fluctuates, the question of how to integrate the fluctuating, non-firm power from Fire Island into the Southcentral grid has become a major bone of contention between CIRI and the power utilities. Presumably the fluctuations in Fire Island power would have to be accommodated by making equal and opposite changes in the power output from one or more generators in gas-fired power stations. But who would make those changes in gas-turbine output, and who would pay for the capacity to be able to make those changes?
ML&P wants to see an in-depth study of the Railbelt power integration issue before power purchase agreements are signed.
“If the island is producing 17 megawatts to 25 megawatts and all at once starts producing 5 megawatts or 10 megawatts … that has to be picked up by one half or one whole turbine, which has gas requirements, scheduling requirements and personnel requirements,” Posey said.
There are contractual costs associated with having available the generation capacity needed to support the fluctuations in wind power output, he said.
“It’s a zero sum game,” Posey said. “Someone has to carry the cost of integrating a non-firm process.”
Scheduled power In their March 30 letter Posey and Gibbons said that ML&P will require the Fire Island wind farm to provide a schedule of its anticipated power output a day in advance, with the wind farm being responsible for alternative generation arrangements if that schedule cannot be met. ML&P cannot commit to paying any cost for power beyond the avoided cost of the power that the wind power replaces, the letter says.
But this requirement would require the wind farm to contract with another utility for services to firm up the power supply to meet contractual obligations — it would be cheaper for ML&P to firm up the power supply itself, Jager said.
In November CIRI said that power utility Chugach Electric Association had commissioned a study into the potential cost of integrating Fire Island power into the grid. That study came up with an estimated integration cost of $100 to $110 per megawatt hour of wind-generated power, an estimate that CIRI has vehemently disputed, saying that, based on comparisons with actual integration costs in the Pacific Northwest, the cost would only be a fraction of that figure.
And part of the issue is the question of whether the power generation capacity needed to cover the fluctuating power supply from Fire Island should be viewed as dedicated to supporting the wind farm, or whether this capacity would be part of more general “spinning reserves” used to back up other supply fluctuations or interruptions.
NREL comments CEA has obtained technical assistance from the U.S. Department of Energy’s National Renewable Energy Laboratory in evaluating the use of power from the Fire Island wind farm. In a Nov. 29 letter to CEA, NREL senior project leader Brian Hirsch said that it is not clear precisely what integration costs renewable energy sources would impose on the Railbelt grid, nor is it clear how those costs should be allocated. However, the Fire Island wind farm would be a step toward reducing the region’s dependence on natural gas, he said.
“The overall Railbelt is greatly in need of a systematic integration analysis to optimize intermittent renewable and all future generation, and we believe that the eventual analytical model that comes from this process should not be the exclusive property of a single utility or consulting firm,” Hirsch wrote
However, Hirsch also said that NREL cannot support the existing production cost model outcomes used to assess Fire Island integration costs.
“Though many areas of disagreement and/or uncertainty remain, it is our opinion that sufficient analysis has been conducted to conclude that the Fire Island wind farm can be reliably integrated into the Railbelt system and — depending on the future price and availability of gas — at reasonable cost,” Hirsch wrote.
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