The best strategy for meeting Puget Sound Energy’s long-range electricity demand is for the utility to continue promoting energy efficiency, acquiring additional power supply for periods of peak customer usage, and securing enough renewable-power resources, over time, said the company in a draft 2013 Integrated Resource Plan (IRP) released April 1.
Updated every two years, the draft plan forecasts PSE customers’ energy requirements 20 years into the future and suggests the resource options most likely to meet customer energy needs at the lowest cost and risk.
The draft IRP notes that development of vast North American shale deposits of natural gas has steeply driven down the commodity’s market price, which in turn has softened electricity prices. The draft plan adds, however, that “it is not realistic to expect natural gas prices to remain this low over the long term. The very affordability of this fuel means that usage is also increasing, especially in the transportation and utility [power-generation] sectors, and this will create upward pressure on prices over time.”
The market price for natural gas, which topped $13 per dekatherm (MMBtu) in 2008, is currently trading in the $3.50 to $4 range, the company noted. The draft IRP sees wholesale gas prices rising to the $6 to $7 range by 2020. Meanwhile, the cumulative, 20-year cost of securing PSE customers’ electric supply is projected to be $13.8bn. While that figure is slightly above the 2011 IRP’s forecast, it is far below the 20-year, $20bn PSE power cost predicted four years ago.
“The surge in domestic production of natural gas over the past few years has been a game-changer that’s benefiting our customers and our economy,” said Booga Gilbertson, PSE vice president of Operations. “What hasn’t changed, though, is PSE’s fundamental game plan for giving our customers safe, dependable, efficient energy service.”
The draft IRP predicts that, 20 years from now, PSE will need about 40% more natural gas supply – about 380,000 dekatherms more per day – to serve its customers’ peak, wintertime demand for gas. Current peak-day demand is about 930,000 dekatherms.
An additional 156,000 dekatherms per day will be needed by 2033 to fuel PSE’s simple-cycle gas-fired plants. This added supply capacity represents a 90% increase in the natural gas used by PSE’s fleet of peakers.
Peakers appear more cost effective than combined-cycle plants, said the IRP. This finding holds as long as the peakers are equipped with oil back-up and a sufficient amount of interruptible natural gas pipeline capacity is available for fuel delivery. This should certainly be the case for the first few additions, but adding several hundred MW of new peakers may over-tax the natural gas infrastructure, the IRP added. Should peakers require firm pipeline capacity, some level of combined-cycle combustion turbine (CCCT) plants may be found to be cost effective.
Expanded use of natural gas across the region could strain its gas infrastructure, the draft IRP says. Ensuring sufficient gas supply regionally may require expansion of the Northwest’s gas-transmission pipeline system and more underground gas-storage capacity. Another option could involve PSE developing a liquefied natural gas facility that not only would help the utility meet customers’ peak-demand periods but also could serve marine and road transportation powered by clean-burning natural gas.
Power purchases, energy savings meet much of near-term power supply needs
By 2033, PSE will need to secure nearly 5,400 MW of additional power resources to meet customers’ peak electricity demand, according to the draft IRP. The utility can shave off almost 1,000 MW of that need by helping customers save energy. Much of the remaining supply can be obtained, particularly in the near term, through cost-effective market-power purchases. But longer term, as regional power demand begins to exceed existing generation capacity, less reliance on market power may be warranted, the draft IRP said.
PSE will also need to acquire another 300 MW of renewable energy by 2022 – and 600 MW by 2033 – to maintain compliance with the Washington Energy Independence Act (I-937). The voter-approved law requires utilities to provide 15% of their customers’ electricity from renewable sources by 2020. PSE today is the top utility producer of renewable energy in the Northwest, with 773 MW of generating capacity from its three large wind farms in Washington.
The draft plan found that continued operation of the co-owned, coal-fired Colstrip Generating Station in Eastern Montana as part of PSE’s diversified energy portfolio remains economical for PSE customers under most of the likely future scenarios examined. The draft plan, however, did identify some future market conditions or potential regulations which could impact that finding. PSE owns about one-third of the 2,094-MW plant’s output.
Colstrip, a minemouth plant with various co-owners including PPL Corp. (NYSE: PPL), provided 16.7% of PSE customers’ total power supply in 2012. The draft IRP’s base-case analysis suggests that continued Colstrip operations would save PSE customers about $150m per year in power costs. Replacing Colstrip power with a combination of gas-fired resources and market power would require a 7% increase in PSE electric rates and increase the volatility of customers’ bills.
“A decade-long surplus of power-generating capacity in the Northwest will soon be gone,” PSE noted in a statement about the IRP findings. “Once coal-fired power plants in Boardman, Ore., and Centralia, Wash., are retired starting in 2020, reliability of the region’s electric grid will ‘erode’ unless replacement power plants are built. The draft IRP notes that PSE will devote additional study to this issue through an update to the plan later this year.”
Colstrip, like many coal plants, has environmental issues to deal with
Among the environmental challenges for Colstrip is EPA’s Mercury and Air Toxics Standards (MATS), due to take effect in April 2015. The mercury control system installed at Colstrip to meet a previous Montana mercury rule will also meet
MATS requirements for mercury capture and removal, the draft IRP noted. The existing scrubbers on all four units adequately remove acid gases covered by the rule. Some investments for additional particulate matter (PM) control by the Unit 1 and 2 scrubbers are anticipated in the environmental compliance cost cases developed for the IRP to comply with the heavy metals requirements of the MATS rule. The Unit 3 and 4 scrubbers already remove the required level of PM.
Another compliance issue is EPA’s Regional Haze Rule. Major sources that began construction before 1977 (this includes Colstrip Units 1 and 2) must also bring emission controls to Best Available Retrofit Technology (BART) standards. The state of Montana declined to prepare the necessary haze studies, so the requirement defaulted to the EPA. The EPA published its Final Implementation Plan (EPA FIP) for Colstrip, covering both the BART and Reasonable Progress requirements in September 2012 with implementation required within five years. The EPA FIP requirements have been appealed to the U.S. Court of Appeals for the Ninth Circuit, the draft IRP noted.
The final IRP will be filed with the Washington Utilities and Transportation Commission by May 30.
Washington state’s oldest local energy utility, Puget Sound Energy serves 1.1 million electric customers and more than 760,000 natural gas customers in 10 counties.