THE power crisis in California had effects far outside the state lines. The Californian power industry is tightly bound to its counterpart in the Pacific Northwest, partly because their load patterns are generally different and complementary. In the north the biggest loads come in winter for heating, and industry is energy intensive. In the south summer air conditioners impose the biggest load. The two systems sell electricity back and forth on a yearly and daily basis as the pattern of load changes. So when electricity prices increased a thousand-fold in California, and capacity remained tight way after the summer peak, electricity companies in the northwest suffered too. Add to that the driest year this century, and the mainly hydro companies in the northwest had a year that none would care to repeat.
Below, representatives from two northwestern companies explain how they managed their way through this period.
Bonneville Power Administration
Bonneville Power Administration (BPA) is a government-owned corporation responsible for marketing the power from 31 hydroelectric plants on the Columbia river and its tributaries, owned and operated by the Army Corps of Engineers and the Bureau of Reclamation. The total capacity of the dams is some 22GW. BPA is required by law to serve all the public load of retail utilities, and a portion of the residential and small farm load of the region’s investor-owned utilities. It has historically also supplied electricity for the region’s extensive aluminium smelting industries. David Mills, trading floor manager, tells the story of the last year.
‘The power exchange in California was rife for gaming because of the split day ahead and real time markets. Generators withheld capacity from the day ahead markets and forced Independent System Operators (ISOs) to compete for capacity in the real time market.
‘We started the year last October much as usual. In the trading floor market prices had been creeping up, but there were underlying reasons for that.
‘At BPA we slowed down our forward selling. Usually forward contracts would be around 30-40% to hedge our revenue but we kept it down below 10%. In October and November we came under very heavy pressure to sell. At that time the price was US$30-40/MWh.
‘By mid-December we had a big water problem but during that month the spot price went up from US$65 to US$250/MWh in two weeks, so we couldn’t buy our way out of the deficit.
‘We set aside some money for cold snap peaking so we could take coal options, for example. So we looked at our native loads and began negotiations with the aluminium industry. In the mid 1990s BPA’s rate had been above the market and at that time some of our customers threatened to leave, so we gave them contract concessions. If it was more advantageous for them to sell electricity than make aluminium then they could, and this is what happened. The companies continued to pay US$25 for their electricity and the market price was US$2-300. So BPA acted as a ‘broker’, marketing the aluminium companies’ electricity to the private sector. We made no money out of it: in fact we lost a lot of what we could have made by selling BPA’s own electricity to those customers. But we freed 1200MW of flat load, so we could meet capacity constraints and we had some flexibility.
‘Then we went to the public utilities and the investor-owned utilities and said we would pay them to take load off the system. They managed to take off about 700MW, mostly from big industrial consumers.
‘Losing that load had a big economic impact, when you consider that some days in January we were paying $1200/MWh.
‘Peak load times in the northwest and southwest vary, so the utilities routinely take advantage of spare capacity at times of low load.
‘We had an exchange with California. Because we have some flexibility and can store at night, we sent surplus to them and got 2MW back from them for each megawatt we sent.
‘We trade in 25MW increments and at US$60/MWh we would typically be making trades of US$1.2M, but there was a period when we were making trades of US$5-6M.
‘We learned some important lessons this year. We really lowered the load too much to the point where we didn’t have enough load to operate our plants at their minimum capacities. It was an executive overreaction to the stream flow situation. Some big loads on the system disappeared completely and it impacted minimum operating levels and transmission operation. On an hourly and ten-minute dispatch it made it very hard to balance the system.
‘We also learned about not selling forward. Some investor-owned utilities took aggressive forward selling positions but you don’t want to be a buyer in this market.
‘Prices are now way down. They dropped about US$235/MWh in 14 days during June and now the range has changed from US$65-1200 to US $20-30/MWh. The markets are somewhat liquid, although not as much as normal.
‘This coming year? My personal guess is that if it doesn’t rain in the next couple of weeks [October] the market will be pretty skittish and prices will go up rapidly. Now we have a cap of US$90/MWh and people are playing both sides. Some are trying to meet their system commitments and save their customers, while others are waiting for higher prices.
‘This year the best bet is to approach the market cautiously. We don’t want to leave the system with a reliability problem and we have to balance that against cash flow. We want to get some of that flat load back on so we are operating above our minimums at night. Then we can import at night and store our water, so we can use it during the day.
‘We have also bought into two 2000MW combustion turbines which will come into operation at the end of the year.’
Seattle City Light
Seattle City Light (SCL) is a city-owned electricity utility serving residential, commercial and industrial users in the Seattle area. As well as buying power from other suppliers it operates seven hydroelectric plants.
Tony Kilduff, strategic advisor, takes up the story.
‘There was no shortage of electricity on the West Coast. There was the same amount of capacity in California – about 54GW- as there had been before, and we’ve seen loads higher there than we saw last summer. It was a clear case of capacity withholding. The Federal Regulatory Energy Commission (FERC) had a responsibility to customers to ensure electricity prices are just and reasonable. It should have stepped in but it didn’t.
‘Problems began in May 2000 when major generators in California figured out the possibilities. Supply contracted as they headed into the cooling season [air conditioning]. People can’t adjust demand that quickly, and their utilities have an obligation to serve them. Generators, on the other hand, could choose to operate or not based on price and profit.
‘Early in 2000 we were selling our share in a coal-fired station for environmental reasons – that lost us 107MW, or about 5% of our peak needs. We were a little short, but we weren’t overly concerned. By this July, we expected to have100MW from a gas-fired plant, and by this October, another 255MW from a new BPA contract. Anyway, with prices triple what we’d seen before, we decided to hold off until things settled down.
‘By September we could see that these wildly high prices were not coming back down. We knew then we wouldn’t meet our financial targets for the year and went to our City Council. We told them we had a US$60M hole – about 15% of our annual operating costs – and they agreed to a temporary 10% rate adjustment to take effect 1 January 2001.
‘In mid-November, water flowing into our Boundary dam halved. That was worrying, but it was too soon yet to know if we were heading into a bad water year. We’d seen things like this before and the water-year turned out fine. The forecast was for a relatively wet year, so we just held our breath. By December it was clear that we were in a drought situation just as we headed into our peak load season. Our US$60M problem ballooned to US$120M in just two months. We cut the generation forecast but it never seemed enough – for the next three months our forecast chased reality down a steep slope. It was scary. We appealed to FERC to step in with a West-Coast wide price cap. It claimed it had no authority to act. Besides, as Chairman of the time Curt Hebert told us, given enough time the market will work.
‘We considered using a fleet of gas-fired portable generators as a temporary boost to our system but ran into a problem with emissions here in Seattle. Keeping the lights on meant buying off the market, and that was painful. We spent US$69M in January for power – half of what we would normally spend in an entire year – and by April we’d gone through over US$300M.
‘Worse still, forward prices early this year for the peak cooling season in California – July through September – were US$400-$500/MWh. We were scrambling to save what little water we had to avoid being on the market during that period.
We closed out 2000 with an operating deficit of US$120M, and by the end of this year we anticipate it will be US$570M. That’s bigger than our entire annual budget in a normal year. We couldn’t push this shortfall onto the ratepayers in one go. We’ve had to borrow to keep operating – that’s a situation we’ve never been in before. We issued about US$700M in debt, which is just amazing, but the credit rating companies downgraded us from AA to AA-. When we took on that debt we were expecting to be surplus because of the new resources we are bringing in. At the kinds of prices we saw earlier this year, that surplus would be more than enough to cover the debt. Then everything changed on 19 June. That was when FERC finally decided to act. It imposed a west-wide price cap and issued a “must offer” order for generators if they can generate. The bottom fell out of the market and our surplus is no longer the saviour we thought it would be. We got hammered when prices shot up, and now we’re being hammered as they go back to normal. It seems we can’t win. The rating companies downgraded us again to A-.
‘There are no fancy fixes for this. In the end the ratepayer will carry the cost. FERC should have stepped in sooner. It claimed it had no jurisdiction but then it imposed a temporary cap in California in the Fall of last year. The truth is, FERC was paralysed by an ideological commitment to markets. But these were markets where a handful of players hold all the cards – that’s not what we need.
‘Prices are now in the US$40/MWh range, but there’s no more capacity available than before. If we can meet the load now, although we haven’t come out of the drought yet, how was it a constrained situation before? We’re seeking refunds from power marketers and generators and believe we are owed at least US$270M.
‘FERC’s administrative law judge says there was no necessary connection between California and northwest prices at the time. We’re amazed she can say that with a straight face.’