Rolling Blackouts in Greater Boston? It Could Happen Sooner Than You Think.
Boston Business Journal | June 26, 2014
You can't say we weren't warned.
Grid operator ISO New England filed an alert in December, but not many people were paying attention at the time: If a new natural gas-fired power plant isn’t done in Salem by June 2016, the ISO could be forced to use rolling blackouts to keep the grid operational.
That warning takes on new meaning now that it’s clear that Footprint Power won’t be able to finish its nearly 700-megawatt plant in time. ISO officials, in fact, are scrambling to get support for a plan that would help ensure Footprint’s project gets built for June 2017, when it would be even more important for the region’s grid.
Meanwhile, ISO managers will soon start working on a plan to address the 2016 shortfall. They’ve confirmed that rolling blackouts — they like to call them “controlled outages” — are still on the table for a section of the grid known as NEMA-Boston, essentially from I-495 along the Mass. Pike corridor to the Boston coastline and north to the New Hampshire border. We’re talking about the heart of New England’s economy.
The consideration of rolling blackouts underscores the precariousness of New England’s electricity supply. The Salem Harbor coal and oil plant just went offline a few weeks ago, one of many older power plants that have closed recently or will shut down soon. The threat to reliability across New England is something that keeps ISO officials up late at night. But nowhere in New England is this threat more real than in NEMA-Boston.
The nearly $1 billion gas-fired plant in Salem, which Footprint Power wants to build to replace the power plant that just closed, was ISO’s best hope of meeting the NEMA-Boston’s power needs in 2016. ISO had identified a shortfall for the region of 174 megawatts as of June 2016. To address that need, Footprint bid into a market that pays power plant owners a premium for making generating capacity available in times of peak demand. Footprint, which is developing the Salem plant with Japanese conglomerate Toyota Tsusho, won the right to five years of capacity payments, a crucial element in its bid to line up financing.
One remaining appeal — an air permit appeal filed with the EPA’s environmental appeal board — has stymied Footprint’s construction timetable. Without a resolution, Footprint can’t get the financing it needs to start building. Given that the estimated construction timeline is about 30 months, it’s all but impossible for the new Salem Harbor plant to be done in time.
That means Footprint loses a year on its capacity contract, leaving it with just four years of premium payments to reward investors and pay back lenders. That probably won’t be enough to get Footprint’s project off the ground. Footprint Power President Scott Silverstein tells me anyone in the industry would say that four years of capacity payments would make it challenging to get financing.
To address this, ISO is proposing a plan that would help power plant developers get a fifth year of capacity payments if a project is delayed by a year. (Silverstein points out that ISO has since changed the rules for future capacity markets to extend the time period to seven years.) ISO officials go to great pains to say this isn’t a bailout for Footprint. But that firm is the only one that would benefit from such a shift right now.
The members of the New England Power Pool, an industry advisory group to the ISO, aren’t rushing to support the plan. NEPOOL’s markets committee rejected it earlier this month, and NEPOOL’s participants committee is expected to take a similar vote during NEPOOL's summer meeting in Maine this week. NEPOOL’s resistance doesn’t necessary kill the plan’s chances, but it could make it tougher for ISO to get the federal approval it needs. Without financing for Footprint’s plant, it’s an open question as to whether a project will be done in time for 2017 or 2018. (Silverstein, for his part, says he’s confident that financing will come through and the new Salem plant will be done in time for June 2017.)
But the more pressing shortage will hit NEMA-Boston in 2016. Gordon van Welie, ISO’s CEO, tells me there are three potential steps the grid operator can take to address the shortfall. Firms that help big users of power get reimbursed for using less electricity during peak times, something known in the industry as “demand response,” could come into the market to fill some of that needed capacity. Van Welie says he is skeptical that demand response can fully meet NEMA-Boston’s need for power.
The next step? ISO could pay to bring in diesel generators on trucks or by barge to help meet the shortfall. This was done in Connecticut a little over 10 years ago. But in its December warning filed with the state Supreme Judicial Court, ISO said that trailer-mounted diesel generators could face strong opposition and might not be installable.
The final option is the one that includes the rolling blackouts. ISO said in December that it could be forced to pursue rolling blackouts in NEMA-Boston to protect the integrity of the broader grid on particularly hot or cold days, or if other resources fail. As part of this third option, a spokeswoman for ISO says the grid operator would work with utilities to consider alternatives, such as voltage reductions for certain large users, before resorting to controlled outages. Such a measure is an extreme step: The spokeswoman says controlled outages have been used only on rare occasions in local areas for short periods. She says ISO will start its operational analysis of how to address the shortfall after the peak summer season is over, with a goal to report the results by early 2015.
NEMA-Boston is only one portion of the New England grid. But the electricity shortfall issues probably won’t stop there, not with all these old-school power plants closing for good. (Say farewell to Brayton Point, Vermont Yankee and Norwalk Harbor.) ISO New England recently identified a looming shortfall for the entire New England region: The grid operator predicts a roughly 143-megawatt deficit — the equivalent of the power needs for about 140,000 homes — for the twelve months that begin in June 2017.
If ISO can address the NEMA-Boston shortfall by June 2017, that could help avoid the reliability issues in other parts of New England. But if the Salem power plant isn’t online by June 2017, ISO officials could have a bigger, broader problem on their hands.
What the EPA Emissions Plan Means for Energy Efficiency and Demand Response
Utility Drive | June 26, 2014
For utilities and states that rely heavily on coal power, the Environmental Protection Agency’s (EPA) new emissions reduction proposal could have been the nail in coal’s coffin.
That will not necessarily be the case, Malcolm Woolf, SVP of government affairs at Advanced Energy Economy, a trade organization for the advanced energy industry, told Utility Dive.
“I sometimes am asked to put myself in the shoes of an electric utility executive with a large amount of coal in my fleet,” he said. To ensure that coal plants continue to be profitable under the EPA's plan, states and utilities will need “to decarbonize the grid in other areas.”
"Investments in efficiency lengthen your other investments,” Woolf said.
“If you build a hotel for 1000 guests, but only usually have 200 guests, it would be out of business pretty quickly,” Woolf told Utility Dive. Similarly, building out the electricity system to meet a few hours of peak demand per year “is kind of crazy.”
“You can use demand response, flatten that out, and not have to build such a huge amount of over-investment for a few hours a year,” he said. Energy efficiency and demand response are products and services “that the grid does not yet really monetize, but that we can monetize, and I think this EPA rule will help us do that.”
Of the four broad-strokes compliance strategies -- coal to natural gas power plant conversions, environmental upgrades at existing power plants, new renewable energy and demand-side energy efficiency -- outlined by the EPA, energy efficiency is the cheapest, cleanest and most achievable system of emissions reduction under the agency's CO2 emissions rule, advocates say.
“The biggest bang for the buck is efficiency," EPA administrator Gina McCarthy recently stated. "It’s getting waste out of the system from the power plant to the plugs.”
A 1.5% annual reduction in overall electricity usage is possible, according to the EPA, if states implement “demand side energy efficiency."
The EPA names “energy efficiency programs, building energy codes, state appliance standards (for appliances without federal standards), tax credits, and benchmarking requirements for building energy use” as possible mechanisms to drive demand-side efficiency, but leaves it up to the states to pick and choose their own preferred compliance methods.
By implementing greater demand-side and end-of-use energy efficiency, the U.S. could reduce CO2 emissions 26% by 2030 compared to 2012 levels, according to a report from the American Council for an Energy-Efficient Economy -- a more significant reduction than the EPA's projected emissions cut under its own rules. This would avoid the need for an additional 494 power plants and reduce U.S. electricity usage by 925 million megawatt-hours.
In a state-by-state analysis, ACEEE found this level of emissions reduction and energy savings would be achievable if states “implement an energy efficiency savings target; enact national model building codes; construct combined heat and power systems; adopt efficiency standards for products/equipment.”
"End use efficiency that reduces total demand for electricity is almost always the best, cheapest thing to do," Lena Hansen, a principal with Rocky Mountain Institute's electricity practice, told Utility Dive. "I can't say what states will choose to do, but when faced with replacing significant coal capacity, efficiency is a cost-effective choice."
"It's also comparatively easy to access," explained Hansen. "It doesn't require several years to build like a big power plant, but rather than be put in place usually very quickly."
But a challenge to implementing these and other efficiencies is that utility revenue traditionally derives from electricity sales. More energy efficiency means less electric sales, which ultimately equals less money. Decoupling utility revenue from electric sales is seen as the best way to, at the very least, render utilities indifferent to energy efficiency. Until that happens -- in some states, it already has -- utilities are largely be disincentivized to invest in energy efficiency.
Under new rule, EPA 'need to be more specific'
“Demand response and smart grid offer new business models for utilities that they should probably be considering anyway,” Dan Delurey, Executive Director of the Association for Demand Response & Smart Grid, a trade association for electric utilities and smart grid vendors, told Utility Dive.
The EPA is to be “commended for their flexibility” in devising the draft rule, Delurey said. In its proposal, the EPA “doesn’t preclude anything” from being part of an energy efficiency and demand response-driven compliance plan. But leaving the question of what policies and program to implement open to interpretation is not ideal, either.
“I think there is creativity and customization that could be done in the bounds of a state plan,” Delurey said. “We are asking EPA to be a bit more acknowledging as to what smart grid and demand response can offer so we don’t have to start from scratch educating state regulators.”
“They need to be more specific,” he explained.
The Advanced Energy Economy recently put out a report that details forty different energy efficiency and demand response technologies and services available to states and utilities, from better building insulation to distribution voltage regulation.
While nothing is necessarily missing from the EPA rule, "some clarity" is needed for states and utilities, Sara Hayes, Senior Manager and Researcher for Policy and Utilities at ACEEE, told Utility Dive.
If she were a state regulator, Hayes explained, she would want to know exactly what "demand-side energy efficiency" means.
The EPA proposal's acknowledgement of not only the potential of energy efficiency, but the emissions reductions already achieved by some states through increased efficiency, will ultimately be beneficial, according to Woolf. The proposal notes that twelve states are on pace to or have already reduced their annual energy consumption by 1.5%, in particular citing California, which reduced projected electricity demand by 12.5% in 2012 via demand-side efficiency programs.
For states without robust energy efficiency programs in place, meeting the 1.5% reduction rate will take more time. Those “already at or above” 1.5%, according to the EPA, can “realize a 1.5% rate in 2017 and maintain that rate through 2029.”
Not only does the evidence show that this goal is “eminently doable,” said Woolf, but it is “pretty conservative.” In Maryland, for example, the 1.5% target has already been met. If the target is achievable with present-day technology and services, he said, then advances made in the next 16 years will only increase states' and utilities' abilities to meet the energy savings goal.
Natural Gas and Oil Market Update
Natural Gas Prices Fall Further After EIA Data
Market Watch | June 26, 2014
Natural Gas futures on Thursday lost more ground after the U.S. Energy Information Administration reported that supplies of natural gas rose 110 billion cubic feet for the week ended June 20. Analysts surveyed by Platts forecast an increase of between 102 billion cubic feet and 106 billion cubic feet. Total stocks now stand at 1.829 trillion cubic feet, down 690 billion cubic feet from a year ago and 822 billion cubic feet below the five-year average, the government said. July natural gas was at $4.45 per million British thermal units, down 10 cents, or 2.3%. It was trading at $4.54 before the data.
Brent Falls for Second Day as Iraq Output Seen Rising
Bloomberg | June 26, 2014
Brent crude fell for a second day on signs that the insurgency in northern Iraq won’t curb output in OPEC’s second-biggest producer. West Texas Intermediate dropped after U.S. consumer spending grew less than forecast.
Brent for August settlement fell 54 cents, or 0.5 percent, to $113.46 a barrel on the London-based ICE Futures Europe exchange at 9:01 a.m. in New York. The volume of all futures traded was 15 percent below the 100-day average for the time of day. Prices have increased 2.4 percent this year.
WTI for August delivery slipped 41 cents, or 0.4 percent, to $106.09 a barrel on the New York Mercantile Exchange. Trading volume was 30 percent lower than the 100-day average. Futures are up 7.8 percent this year.
The U.S. benchmark crude traded at a $7.37 premium to WTI, down from $7.50 yesterday.
EIA - Weekly Natural Gas Storage Report
Working gas in storage was 1,829 Bcf as of Friday, June 20, 2014, according to EIA estimates. This represents a net increase of 110 Bcf from the previous week. Stocks were 690 Bcf less than last year at this time and 822 Bcf below the 5-year average of 2,651 Bcf. In the East Region, stocks were 382 Bcf below the 5-year average following net injections of 68 Bcf. Stocks in the Producing Region were 340 Bcf below the 5-year average of 996 Bcf after a net injection of 25 Bcf. Stocks in the West Region were 100 Bcf below the 5-year average after a net addition of 17 Bcf. At 1,829 Bcf, total working gas is below the 5-year historical range.
NYMEX Natural Gas Week-to-Week Price Change
Natural Gas Futures - Five Year Price ($ per mmBtu)
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