The Final Word on Winter in New England’s Energy Markets, Part II: Why This Winter Was Different

Mar 25, 2015 by  | Bio |  1 Comment »

As late as last fall, many observers and traders watching the New England energy markets were predicting a repeat of last year’s very expensive winter, or worse. By January, CLF was able to post an update showing that those predictions weren’t materializing. In fact, the expected energy crisis was fizzling, with much lower wholesale power and natural gas prices than last year and no signs that gas-fired power plants were struggling to get fuel. We laid out a series of market shifts and changes that were making a difference.

Two kids cross country skiing in a snow storm on a woods road near Greenville, Maine.

As I mentioned in the first part of this series on this winter in New England’s energy markets, February was a major test for New England’s energy system. It was the coldest February in modern times, with bitter cold, record-breaking snowfall, and no “February thaw” whatsoever. Adding to retirements of several major non-gas power plants in 2014, some of New England’s remaining non-gas power plants experienced outages or problems. The whole Northeast was much colder than normal, driving record natural gas demand for heating and electric generation. On February 2, New England set an all-time record for daily gas demand of 4.21 billion cubic feet.

Despite the challenges, the factors we identified in January helped keep prices in check and the lights on for the balance of the winter:


  • Thanks to the global crash in oil prices, fuel oil was available for about half last year’s price, moderating the price of liquefied natural gas, which is linked to oil prices. During the coldest weather, especially in February, lower oil prices directly lowered power prices as well because, with oil cheaper than spot-market gas, oil-fired power plants (or gas-fired power plants with the capability to run on oil) were setting electric market clearing prices. While it’s not good news that more-polluting resources like oil and coal plants were able to run, they did not run as much this winter as last winter (even accounting for dual-fuel oil demand):


  • Regional grid operator’s ISO-NE market changes implemented in December, including hourly offers and re-offer opportunities, improved price transparency and formation, which clearly helped dampen and lessen the duration of cold weather price spikes. Other gas-electric coordination steps encouraged by the Federal Energy Regulatory Commission also made a difference. What we’ve seen in March is a rapid drop in prices from February levels, something that didn’t happen last year in similarly cold weather.

This winter, we also saw reasons to worry less about two other concerns: the very real and legitimate hardships of this winter’s high retail prices for ordinary customers and the ongoing retirements of older power plants.

  • With lower oil prices, households and businesses also have been paying much less for oil and petroleum fuels this winter. A January government estimate puts these savings in 2015 at $1500 for the average family that both drives and heats with oil, and at $750 for the average family that drives and heats with other fuels. These savings are totally offsetting (and more) the $30 to $50 monthly increases in average electric bills that some New England households are facing through the first part of the year. And as noted in the first part of this series, summer electric rates are on the way down; when 2015 is over, average electric supply rates for the year will be higher than in 2014, but by far less than the eye-catching percentages cited in the news reports announcing this winter’s retail increases.
  • In February, ISO-NE held its annual auction to buy electric generating capacity to meet the region’s electric needs three years from now. As my colleague Jerry Elmer noted at the time, that auction successfully procured an overall surplus beyond the very high “installed capacity requirement” that ISO-NE has determined is appropriate. With somewhat higher prices than past auctions, ISO-NE’s capacity market is serving its purpose—to ensure that new power plants, especially wind and natural gas, will be replacing the plants set to retire in the next few years. Another signal of a strong market for new resources came earlier this month, when 16,000 megawatts of new generating capacity (an amount equivalent to nearly half of the region’s power plant fleet) expressed an interest in participating in next year’s capacity auction for 2019-2020. Analysts are expecting capacity prices to decline in future auctions as these new power plants compete against each other. Our region’s growing energy efficiency and solar investments will also moderate peak demand and keep overall electric demand flat, as acknowledged in ISO-NE’s plan to count behind-the-meter solar generation in calculating that demand and its energy efficiency forecast.

With this winter behind us, what are its lessons for future winters—and our region’s energy future? With massive proposals for new energy infrastructure on the table, with supposed goals of solving our winter energy problems, what should New England do next? I will explore these issues in the next post in this series.

I followed New England’s energy markets all winter on Twitter at #winterenergycrisis. A Storify collecting my best tweets, with more market data and charts, is here.

(photo: Two kids cross country skiing in a snow storm on a woods road near Greenville, Maine, copyright Jerry and Marcy Monkman/EcoPhotography)

The Final Word on Winter in New England’s Energy Markets, Part I: The Difference a Year Makes

Mar 24, 2015 by  | Bio |  3 Comment »

With the sap finally running, the snow slowly melting, and the vernal equinox past, it’s time to look back on winter in the New England energy markets.

Despite dire predictions and some of the worst winter weather on record, there wasn’t a crisis. Modest market shifts made a huge difference, driving down prices, assuring the lights stayed on, and calling into question the wisdom of the region making big new bets on gas pipelines and transmission infrastructure.

In this multi-part series, I will run down the market data on what happened this winter, offer a few explanations, and explore the lessons we should take from the experience as the region looks to its energy future.

Sap buckets on maple trees on a dirt road in Pomfret, Vermont.

Last year, after a very expensive winter in New England’s wholesale energy markets, many were predicting the worst this winter. Ever higher prices. Economic ruin and job losses. Maybe even rolling blackouts on the coldest days. As the leaves were changing colors, electric utilities throughout New England locked in winter power purchases at double the rates most were paying last summer. The newspaper articles and radio stories almost wrote themselves and even went national, as it seemed everyone was talking about energy costs and the apparent culprit—a severe deficit of gas pipeline capacity to transport cheap Marcellus shale gas from the mid-Atlantic and Midwest to heat New England’s buildings and to power our gas-heavy power plant fleet on cold days.

In mid-January, CLF was among the first to see that the supposedly inevitable New England winter energy crisis was fizzling. Natural gas and wholesale power prices were down compared to last year’s prices—way down. Gas from better-utilized pipelines and shipments of liquefied natural gas were amply supplying power plants, even on cold days. Despite higher electric bills, lower oil and gasoline prices were helping many consumers pay less overall for their energy needs than last winter.

Little did we know at the time that February would be among the coldest and stormiest in recorded New England history. While we can expect more weather extremes like this in future years thanks to climate change, February tested the system in ways that, if the pre-winter fears were borne out, would have brought us the full parade of horribles: rolling blackouts, even higher gas and power prices than last year, and major harm to the region’s economy.

In the end, as week after week of cold and snow battered the Northeast, prices in the energy markets did go up. But they didn’t match last year’s peak prices. Here is the final version of my chart showing hourly and daily average wholesale electricity prices on the New England electric grid, comparing last year’s and this year’s prices.


(Keep in mind that $10 per megawatt-hour is the same price as 1 cent per kilowatt-hour. Typical homes use between 500 and 750 kilowatt-hours of electricity per month. The prices I’m analyzing relate only to the supply of electricity from power plants; electric bills also include a charge per kilowatt-hour to deliver the power through the transmission and distribution system and other fees and charges.)

In the end, despite the jump in prices in February, the peak weekly wholesale power price in New England was much lower than last winter, and the lowest winter peak in three years. In fact, that peak weekly price—about 15 ¢/kwh in late February—was less than some retail rates that utilities locked in last fall, not just for the winter but for the first six months of 2015. That’s how wrong last year’s predictions about winter prices were.


It’s true that the cold drove up February power and natural gas prices, likely making the month the most expensive of the year. As a result, the region’s oil and coal power plants were temporarily able to compete, running more than in other seasons, when they barely run at all. But however you look at this winter—day-by-day, week-by-week, or month-by-month—wholesale power prices were below last year’s prices.


Overall, from December 1 to March 20, prices were down 45%. That’s despite the fact that this winter was colder overall than last year, with a temperature in the Boston area about 4°F below historical averages and 1.5°F colder than last year.

These lower wholesale prices mean that it is very likely that next winter’s retail electric prices will be lower than this year’s—power futures for next January and February are now trading between 10 and 12 ¢/kwh, with the other winter months of December and March lower than that. We are already seeing dramatic reductions in retail electric prices for this summer; last week National Grid announced that its supply rate for Massachusetts customers will drop from 16 ¢/kwh to less than 9 ¢/kwh on May 1; this week, the New Hampshire utility Liberty Utilities announced summer rates of less than 7 ¢/kwh, down 55% from its winter rates.

In terms of reliability, the region’s electric grid didn’t miss a beat, despite unfortunately timed outages at the Pilgrim nuclear power plant that took that station offline for many days and the fact that four large non-gas power plants that were available last year—Mount Tom, Norwalk Harbor, Vermont Yankee, and Salem Harbor—are now retired. In the brutal cold and higher priced days of February, ISO-NE never once activated its long chain of alerts and precautions, known as Operating Procedure No. 4, that is triggered when system reliability is at immediate risk.

Why did the markets have such a different winter this year?  I will tackle that question in the next part of this series.

I followed New England’s energy markets all winter on Twitter at #winterenergycrisis. A Storify collecting my best tweets, with more market data and charts, is here.

(photo: Sap buckets on maple trees on a dirt road in Pomfret, Vermont, copyright Jerry and Marcy Monkman/EcoPhotography)

Smart Moves for Maine’s Electricity Grid

Mar 10, 2015 by  | Bio |  2 Comment »

Several years ago, Maine took a small but significant and unprecedented step toward modernizing its electric grid. Rather than implement a traditional “poles and wires” transmission build out to address growing electricity needs in the Boothbay Harbor region, the Maine Public Utilities Commission (PUC) approved an innovative pilot project.

GridSolar's Boothbay Pilot program is finding innovative ways to meet electricity demand without an expensive transmission rebuild.

GridSolar’s Boothbay Pilot program is finding innovative ways to meet electricity demand without an expensive transmission rebuild.

The Boothbay Pilot relies on so-called non-transmission alternatives, or NTAs, to reduce electric load in the region by 2 megawatts (MW). Using these alternatives eliminated the need for an $18 million transmission rebuild, while also improving energy efficiency, reducing greenhouse gas emissions, and saving ratepayers approximately $3 million per year. A smart move. Now, the PUC has the opportunity to take many of the pilot’s concepts statewide.

Non-transmission alternatives are, as the name implies, alternatives to the traditional way of distributing electricity. For most of Maine’s power grid, state-regulated transmission and distribution utilities, such as Central Maine Power, transmit bulk electricity from a generation source – for example, natural gas, oil, or hydro – through power lines, substations, and distribution lines to your home. To ensure reliable and constant energy flow the power grid must be continually maintained and at times rebuilt or upgraded to meet demand.

Instead of expending ratepayer dollars on expensive transmission solutions, electric power needs can be met by various NTAs, including energy efficiency, passive electric power generation closer to the consumer (like solar panels or wind turbines), and active devices that can be switched on when needed to reduce load on the grid. These alternatives create a more efficient grid and reduce total power needed.

For the Boothbay regional Pilot program, GridSolar developed just such an NTA solution. In a case before the PUC, GridSolar has petitioned to become the state’s lead developer of smart grid technologies – a new entity allowed under the Maine Smart Grid Policy Act. While PUC staff recently recommended that the Commissioners deny GridSolar’s petition – in favor of putting the coordinator’s role out to bid for proposals – their report nonetheless recognizes the value in having an incentivized actor forwarding non-transmission alternatives to utilities’ business-as-usual transmission projects.

CLF is an intervening party to this case and has advocated for the PUC to create just such a statewide NTA Coordinator. Designating this role is another small but critical step toward a more efficient and modern energy future for Maine. Another smart move on which we should all agree.

Time to Act: Guest Post by Olivia Gieger

Mar 6, 2015 by  | Bio |  Leave a Comment

Last fall, CLF, Mass Energy Consumers Alliance, and four youth plaintiffs filed suit against the Massachusetts Department of Environmental Protection for failing to fully comply with the Global Warming Solutions Act. In this guest post, one of the teen plaintiffs, Olivia Gieger, explains why she’s joined the court fight to defend her climate future.

As a sophomore in high school, I am all too familiar with procrastination. That group project assigned a month ago and now due tomorrow? We had a month; why start early? It’s a group project; won’t someone else do it? In my experience, I can tell you, those all-nighter–inducing group projects never turn out well.

Don’t be the sophomore in high school.

This 2015, we have the technology to know that atmospheric carbon dioxide levels are rising at an alarmingly fast rate. We’ve had this technology since 1960 when carbon dioxide levels were at 315 parts per million (ppm). Now they’re at 395 ppm(1). We know that this carbon dioxide is a greenhouse gas, which captures heat energy and slows its release from air. While greenhouse gases are necessary in our atmosphere and are needed to keep us warm, an unnatural amount is strikingly dangerous. More greenhouse gases mean more heat held in the atmosphere, which means a hotter Earth.

Side effects of global warming are countless, and they are happening today. Sea levels are rising. Ice caps are melting. Forest fires are raging. Downpours are constant in the Northeast, yet droughts are ever more present in the West(2).

But, really, why should I care? Melting ice caps and a couple less polar bears don’t really affect me, right? I don’t live in California, so those wildfires don’t affect me, either. But other people are being impacted by the wildfires, the melting ice caps, the rising temperatures. The scary reality is that we all are. I may not know anyone who lives in California, but that’s where my food is grown. If there are droughts and wildfires, how is my family supposed to get some of our favorite fruits and vegetables that don’t grow here in Boston during the winter? And those melting ice caps affect a whole lot more than polar bears. When they melt, sea levels rise – not just at the North Pole, but globally. This means my favorite beaches on Martha’s Vineyard will be washed away. It means my favorite restaurants and museums – even my neighborhood – here in Boston will be underwater in my lifetime.

In order to do something about these concerns, I have filed a lawsuit, along with three other youth plaintiffs, against the Massachusetts Department of Environmental Protection (DEP), because DEP has been procrastinating in fully complying with the Global Warming Solutions Act (GWSA). The GWSA requires DEP to pass regulations establishing declining greenhouse gas emissions limits for Massachusetts. But DEP has not done so. The purpose of the lawsuit is to force DEP to comply with the law, because it appears unwilling to do so on its own. Thanks to the support from my lawyers at Sugarman, Rogers, Barshak, & Cohen and Our Children’s Trust, we will ensure that DEP complies with the law.

So now my question is why? Why are we as a society being sophomores in high school about this? Why are we just waiting for someone else to solve this massive problem? We know the problems, and, better yet, we know the solutions. Using clean, renewable energy is one solution. Enough energy from the sun enters the Earth in one hour to power it for an entire year(3). This energy is unlimited, harmless to the environment, and virtually free. Sounds to me like it tops fossil fuels any day. It’s not just solar energy, however – wind power and hydropower are also unlimited and harmless to the environment. So why then are we oblivious to this? Why are we so incapable of making a change? We need to stop procrastinating. It is long past the time to include, encourage, and execute programs with wind and solar power as the energy of America. We cannot afford to be sophomores anymore; it’s time to graduate.

Works Cited:

  1. Pieter Tans, NOAA/ESRL ( and Dr. Ralph Keeling, Scripps Institution of Oceanography (
  2. “The Current and Future Consequences of Global Change.”Global Climate Change: Vital Signs of the Planet. National Air and Space Association, n.d. Web. 14 Nov. 2014.
  3. “Solar Power Energy Information, Solar Power Energy Facts.”National Geographic. N.p., n.d. Web. 16 Nov. 2014.

Growing Clean Energy

Feb 17, 2015 by  | Bio |  1 Comment »

The recent massive snow storms provide a stark reminder of why we need more clean energy. The more fossil fuels we burn, the more global warming we face.  Fiercer and more frequent storms continue to march across New England wreaking havoc with the daily lives and pocketbooks of so many.

Thankfully there are many efforts to bring more clean energy to the region and begin to break our addiction to fossil fuels.

In Vermont, Legislators are taking up a broad bill that would expand renewable energy opportunities. For electricity, the legislation would set the highest standard of any place in the region – 75% renewable by 2032. While much of that electricity would come from existing sources, including imported hydro power from Canada, it sets a new benchmark for what is possible — closing down coal plants, walking away from new gas facilities, and relying on more clean local power. The City of Burlington is already exceeding this standard and showing in real terms how meeting a 100% renewable standard is achievable and saves money for their customers.

The Vermont legislation would require that a full 10% of the electricity in 2032 come from smaller scale local renewable projects. Putting power generation closer to power needs reduces pollution and curbs the need for massive new transmission projects. This builds on the rapid success in Vermont of expanding customer opportunities to rely on renewable power. When combined with energy efficiency that already meets over 13% of our electric supply needs, Vermont jumps well ahead of the curve in bringing about a much needed clean energy transformation for the region.

The legislation also corrects a troubling problem with existing Vermont law. No longer would utilities double-count renewable resources, by both claiming them for Vermont while selling them to customers in other states. The Federal Trade Commission recently criticized this practice in regards to one utility’s activities. Instead, Vermont’s renewable supply would be better integrated into the regional renewable markets. Vermont can continue to sell renewable power in the region and avoid undermining our own efforts to reduce greenhouse gas emissions.

Some of the more innovative aspects of the Vermont legislation begin to tackle the biggest sources of greenhouse gasses in Vermont – fossil fuel used for heating and transportation. As of 2011, heating and industrial uses account for about 32% percent of Vermont’s greenhouse gas emissions and transportation accounts for about 46%. To meet our needed greenhouse gas reductions and avoid future climate disasters, we need to reduce fossil fuels from more than just electricity.

To further reduce greenhouse gas emissions and save money, the Vermont legislation would set binding requirements that by 2032 Vermont utilities provide opportunities for their customers to reduce fossil fuel use for heating and transportation. Projects can include such things as expanding the availability of heat pumps, weatherizing homes and businesses, installing efficient biomass heat, and providing facilities to support electric vehicles. Projects would not only need to provide reduced pollution, but offer clear economic savings as well. This opens up opportunities for partnerships that can break down barriers. Meeting customers where they are and providing the services they need and want at a reasonable cost is the hallmark of any good business. Legislation that paves the way for successful businesses to meet our broader 21st century power needs will position Vermont well to tackle global warming. Keeping a clear focus on the economics and the pollution reduction ensures that all Vermonters benefit from these changes.

With storms raging throughout New England, it is good news the Vermont Legislature is taking action to tackle global warming and help Vermonters save money.

ISO Corrects Its Big Mistake — And Will Count Renewable Energy

Jan 26, 2015 by  | Bio |  2 Comment »

At the January 21, 2015 meeting of the ISO’s Planning Advisory Committee (PAC), the ISO made clear that – for the first time in its history – the ISO is going to count renewable energy Distributed Generation (DG) in calculating how much electricity capacity it buys in its annual “Forward Capacity Auction” (FCA). Although many details remain to be worked out, this is a big win for renewable energy – and one that CLF has been fighting for literally for years.

ISO-New England is the entity that runs the New England electricity grid and wholesale electricity markets; those markets, in turn, determine how much ratepayers will pay for every kilowatt hour of electricity they use. You can read about CLF’s long-standing work with the ISO, here.

Once a year, the ISO runs a “Forward Capacity Auction” (FCA). In a blog post on October 15, 2014, I explained what these FCAs are, and why they are so important:

Once a year, ISO holds what it calls a “Forward Capacity Auction” (FCA) for a one-year period of time three years in the future. The purpose of these FCAs is to ensure that there will be adequate supplies of electricity (that is, enough power generators) in the region to meet the expected load. . . . The technical term that ISO uses to describe what it wants to buy in these FCAs is “Installed Capacity Requirement” (ICR). Don’t be frightened by the name or the acronym: the ICR is the quantity of electricity generation (“capacity”) that is needed (“requirement”) to meet the expected load (electricity usage) during the relevant period.

One reason that these FCAs matter is because a lot of money is involved. The clearing prices of the eight FCAs that ISO has conducted have resulted in real costs to New England electricity ratepayers of between $800 million to $2.2 billion (that is per annum).

For years, CLF (and others) have been arguing that, when the ISO calculates its annual ICR figure, it needs to account for renewable energy DG that is actually on the New England electricity grid or expected to be during the relevant period. The title on my October 15 blog post was: “The ISO’s big Mistake: Not Counting Renewable Energy.” I said:

ISO’s big mistake was not accounting for renewable DG when it projected how much electricity to buy in the next Forward Capacity Auction . . . ISO’s big mistake will cost ratepayers a lot of money. For every 100 MW of renewable DG that ISO failed to count, New England ratepayers will overpay $200 million in the upcoming February 2015 FCA. And ISO’s own estimate (which CLF believes is overly conservative) is that there will be hundreds of megawatts of renewable DG in New England during the relevant period (2018-2019).

On October 6, 2014, CLF sent a letter to the ISO challenging the ISO’s big mistake. As you can see, CLF emphasized the potential savings to ratepayers if the ISO corrected its mistake of improperly ignoring renewable energy. And CLF was not the only one that objected to the ISO’s big mistake. The New England States Committee on Electricity (NESCOE) sent its own letter urging the ISO to count renewables in making its ICR calculation.

As you can see, CLF’s letter to ISO also raised the possibility that, if not corrected in the future, ISO’s mistake could make the ISO’s auction results subject to legal challenge before the Federal Energy Regulatory Commission (FERC). (All major ISO decisions are subject to FERC approval.) In its letter, CLF cited the specific section of the Federal Power Act that such a challenge would be based on and cited specific cases on the topic.

FERC essentially agreed with CLF. On January 12, 2015, I posted a blog on CLF’s website entitled, “FERC Agrees With CLF About the ISO’s Big Mistake, Not Counting Renewable Energy.” In that blog, I linked to a January 2 FERC Order directing the ISO not to make the same mistake again when it next calculates how much capacity to buy in the next Forward Capacity Auction, FCA-10, scheduled to be held in February 2016.

The good news now is that the ISO got the message that CLF, NESCOE, and FERC have all been sending. At the January 21, 2015 meeting of the PAC, ISO staff reported that they will include some renewable energy DG in the calculation of the ICR for FCA-10. While CLF is not completely satisfied with the methodology that the ISO proposes to use, this is nevertheless a huge step forward – because it means that we can now discuss how to account for renewable energy on the system rather than whether to account for it.

In fact, at the January 21 PAC meeting, ISO staff acknowledged the existence of four separate “buckets” of DG on the electricity grid: (1) DG that participates in the Forward Capacity Market and does get a Capacity Supply Obligation from the ISO;  (2) DG that does not participate in the Forward Capacity Market but is known to the ISO’s Control Room as so-called Settlement-Only Generators (SOGs);  (3) behind-the-meter resources that are accounted for already as part of the ISO’s load forecast; and (4) behind-the-meter resources that are not accounted for already as part of the ISO’s load forecast. The third of these four categories will not result in any change in future ICR calculations, because these resources are already figured in to the ISO’s load forecasts. However, there is now opportunity, for the first time, for the other three categories to be accounted for in the ISO’s annual calculation of how much electricity capacity to buy in the annual capacity auctions.

This will result in a classic win-win situation. All New England ratepayers will benefit because they will stand to save literally hundreds of millions of dollars a year by not double-paying for energy. And renewable energy producers will finally start to receive some credit for the electricity that they are putting into the New England electricity grid.

Renewable Energy Bill Introduced Into Rhode Island General Assembly

Jan 15, 2015 by  | Bio |  Leave a Comment

On January 14, 2015, H-5079 was introduced into the Rhode Island House of Representatives. Representative Deborah Ruggiero (D-Jamestown) was the lead sponsor; House Environment Committee Chairman Arthur Handy (D-Cranston) was a co-sponsor. You can see a copy of the bill on the General Assembly’s website.

The bill would extend the life of Rhode Island’s 2004 Renewable Energy Standard, Rhode Island’s first, very successful renewable energy law. CLF strongly supports H-5079, and worked with Rep. Ruggiero to craft its language.

In June 2004, Rhode Island became one of the first states to enact a so-called “Renewable Portfolio Standard” (or RPS). In Rhode Island, our RPS law is called the Renewable Energy Standard (RES). RPS laws are among the most successful renewable energy laws ever enacted in the United States, because they have a track record of actually working to get small, medium, and large renewable energy projects financed and built. California enacted the first RPS in 2002 (with Rhode Island close behind in 2004). Today 29 states have mandatory RPS laws, including five of the six New England states (all except Vermont), as well as New York, Pennsylvania, Texas, Ohio, Illinois, Arizona, and New Mexico.

The principal feature of Rhode Island’s RES Statute is the mandate, or obligation, that Rhode Island’s principal electricity utility, National Grid, buy a certain percentage of its electricity from renewable energy sources, with that obligation increasing over time. The Rhode Island RES Statute started with an obligation to purchase 3% of electricity load from renewables in 2007 and ramps up to 16% of load in 2019. (Of course, the comparable figures for the RPS obligations in other states vary from state to state. For example, the current California RPS, the most ambitious in the nation, ramps up to 33% of electricity load by 2020.) The RES Statute also defines what counts as “renewable energy”: wind, solar, geothermal, and small hydro (under 30 megawatts).

Rhode Island’s original RES Statute was designed to be an experiment, and it is set to expire in 2019. Now that we have more than a decade of experience with the law, and know that it has worked extremely well, H-5079 is designed to extend its life from 2019 through 2035 – with the obligation continuing to ramp up at the substantial rate of 1.5% per year. CLF is working closely with other environmental groups to build broad and strong support for H-5079.

As Cold Sets In, the New England Winter Energy “Crisis” Fizzles

Jan 14, 2015 by  | Bio |  10 Comment »

As of this writing (mid-January), we’re reaching the end of our first major cold snap here in New England, so let’s take stock of how New England’s electric system and market are faring. In short, we are doing much better than expected, to the great surprise of the many “experts” who have said we are in a “crisis.”

(credit: EcoPhotography)

(credit: EcoPhotography)

Despite months of talk about energy shortages and ever-higher prices, wholesale prices for electricity and natural gas are running well below last year, and power plants are getting the fuel they need to run, even in very cold weather. After big power plant retirements, the system is working well, and the forward prices that will set future retail electric rates are also down. Unfortunately, many customers’ bills remain extremely high thanks to poorly timed energy buys by electric utilities, but rates are already falling. The new, calmer reality we are seeing this winter should force rational policymakers to dial back the energy crisis hysteria.

There is no question that there were challenges last winter. As we’ve discussed before, the spot prices for natural gas delivered to New England spiked to incredible heights, and, because natural gas power plants are the dominant power providers in New England, wholesale electricity prices followed suit. Prices stayed very high through March. On a few of the coldest days, some natural gas power plants didn’t get enough fuel to run. Older, dirtier, costlier power plants filled the gap, running much more than usual. While regional grid operator ISO-NE has described the system’s condition as precarious, there wasn’t actually a power shortage or emergency due to natural gas constraints. (On one occasion in December 2013, sudden loss of imports from Hydro-Quebec did cause the grid operator to dip into short-term reserves. A similar incident happened earlier this winter, on December 4, 2014.) As CLF has pointed out, the real issue last winter was a failure to deal adequately with the increased use of natural gas for power generation, not a major deficit in pipeline capacity.

So far, what happened last winter isn’t happening this winter:

  • In December, New England wholesale power prices and natural gas prices were down 55% and 64% from last year, respectively. The average spot price of power was about 4.3 cents per kilowatt-hour. So far in January, we’ve seen an increase in these prices on cold days, especially during the morning and evening “ramps” when we see very brief “needle peaks,” but the increase has been much less than last year.

ISO-NE prices

  • Even in the coldest weather, natural gas power plants are getting the gas they need to run. While December was somewhat warmer than last year, we’ve seen some bitterly cold weather in January, and there has still been enough gas to heat our buildings and serve power plants. And we don’t have any more pipeline capacity than we did last winter. In general, it appears that ISO-NE, power plants, and pipeline companies have learned lessons from last winter about timely communication, coordination, and fuel supply, something federal energy regulators are pushing as well.
  • ISO-NE has implemented a number of meaningful pricing reforms in the wholesale electric market. These changes seem to have helped contribute to more accurate, moderate wholesale prices, including the innovation—well-explained recently by my colleague Jerry Elmer—of allowing negative prices. The power plants running during negative price events are actually paying into the electric grid for the right to operate, reducing the amount we all have to pay. We saw negative spot prices on a number of occasions in December, and we even saw them on a fairly cold night earlier this week. ISO-NE has a more thorough description of its most recent market changes here.
  • Liquefied natural gas is helping. As CLF has argued for several years, making greater use of our existing LNG infrastructure to help supplement natural gas deliveries through pipelines can be a smarter, lower-cost option than building new pipeline capacity and is much cleaner than relying solely on oil-fired power plants. Unlike last winter, ISO-NE opened its “winter reliability program” to LNG this year. The price of LNG is tied to global oil prices, which have fallen dramatically, making LNG deliveries—a new shipment reached the Everett, Massachusetts terminal just this week—an even more cost-effective way to meet high winter gas demand.
  • The market appears to be taking the 2014 retirements of several major power plants (Vermont Yankee, Salem Harbor, and Mount Tom) in stride. CLF sees these retirements as appropriate technology turnover and major opportunities to build the region’s clean energy future. In the wake of these retirements, energy efficiency and renewables are playing an increasingly important role, with thousands of megawatts of these resources expected to come online in the next few years.
  • Looking into the future, New England natural gas and power futures for the rest of this winter and next winter are way down from their recent highs, and less than they have been in more than a year, before last winter’s challenges spooked the market. This trend suggests that market observers are not expecting last winter’s challenges to recur to the same extent in future years.

    Feb. futures

    February 2015 New England power futures sit at $85/MWh or 8.5 ¢/kwh; many utilities locked in winter prices between September and November 2014 (source: CME Group)

If this is what is happening in the market, why are many customers paying so much for power this winter? The answer: profoundly terrible timing and insufficiently flexible buying practices on the part of utilities. The utilities charging the highest rates this winter locked in power buys last fall, at astronomical multi-month rates that in some cases doubled the previous supply rates in customer bills. The upshot: some retail customers are paying more for each and every kilowatt-hour of energy they use through the spring than the wholesale market prices on even this winter’s coldest days.

There are silver linings for even these electric customers: customer bills will return to earth when new rates are set. This week, two utilities that avoided setting rates last fall—Central Maine Power and Bangor Emera—set their prices for this year, and their supply costs dropped almost 15%, to 6.5 cents per kilowatt-hour—less than half what many customers in other New England states are paying this winter. Competitive energy suppliers also are beginning to offer lower prices, and retail choice may allow customers to find a lower rate even sooner. Other utility customers should see substantial drops when their rates change next, and most will have lower bills in time for summer and air conditioning season.

Taking a broader view of customer energy bills to include transportation and heating fuels, the sustained decline in oil prices means that most New England households and businesses are likely to spend less on all their energy this year than last year, even if they pay a high electric rate this winter. While this drop in oil prices may benefit us in the short term and take the bite out of winter electric hikes, relying so much on fossil fuels is a sword that can cut both ways; until we more aggressively shift to the “free” fuels of renewable resources, we will be living with and need to manage the risks of the fossil energy rollercoaster.

ISO-NE's conservative expectations for wind, solar, and efficiency growth

ISO-NE’s conservative expectations for wind, solar, and efficiency growth

Where does this leave the ongoing discussion about our regional energy future? Over the last year, you’ve probably heard the dire prognostications of state officials, industry advocates for new gas pipelines like Kinder Morgan’s Northeast Energy Direct and power lines like Northern Pass, and even representatives of ISO-NE. The message: we don’t have enough gas pipeline; our old power plants are retiring without reliable replacements; we need much more imported power; electric rates will be sky-high until we “do something.” That something is the so-called  “grand bargain” solution, concocted behind closed doors, then put on hold last summer, but likely to reemerge in some form this year. The plan: build lots of big new energy infrastructure, with electric customers footing the bill. We’ve been told that, until that billions of new infrastructure comes online, households and businesses would pay devastatingly high electric bills. So far, this winter has shown that the payoff on this multi-billion-dollar bet is far from assured and likely to be much less than assumed from last winter’s experience, as it’s not clear how much new infrastructure we really need and the region is already saving a great deal without new mega-projects.

With the winter energy crisis narrative fizzling before our eyes, and new political leadership in several state capitals, New England has an opportunity to set a different course this year. We can craft incremental, market-oriented measures that help ensure we meet our energy needs at a reasonable cost, reduce our fossil fuel use and greenhouse gas emissions, and make full use of the infrastructure we have. In a market that can turn on a dime, these are smart moves, and they are already paying off this winter.

Follow me on Twitter as I track the data through the winter at #winterenergycrisis.

FERC Agrees With CLF About the ISO’s Big Mistake, Not Counting Renewable Energy

Jan 12, 2015 by  | Bio |  Leave a Comment

On October 15, 2014, I posted a blog that explained that the ISO, the entity that operates New England’s electricity grid, had made a huge mistake in neglecting to use its own renewable energy forecast in deciding how much electricity to buy for the period 2018-2019.

On January 2, 2015, the Federal Energy Regulatory Commission, the governmental agency that regulates the ISO, issued an Order that agrees with CLF’s position, and tells the ISO to correct its big mistake when it decides how much electricity to buy for the following year, 2019–2020.

Here are the details of what happened. (If you find some of this discussion confusing, read my October blog first, because that explains many of these terms.)

On November 4, 2014, the ISO filed with FERC its projected figure for the Installed Capacity Requirement (ICR) for FCA-9 (that is, Forward Capacity Auction 9, to be held next month, February 2015, for the Capacity Commitment Period that runs from June 1, 2018, to May 31, 2019). CLF voted against the ISO’s figure in NEPOOL, the ISO’s legally mandated stakeholder group. CLF cast this negative vote specifically because that figure (34,189 MW) improperly failed to account for the ISO’s own forecast of renewable energy distributed generation that would be on the New England electricity grid during the relevant period, 2018–2019.

Significantly, a majority of NEPOOL members sided with CLF on this issue. The problem that both CLF and NEPOOL pointed out was that when the ISO calculates an ICR that totally ignores the ISO’s own distributed generation forecast, the resulting rates cannot, by definition, be “just and reasonable” within the meaning of the Federal Power Act, because the ISO is significantly over-procuring capacity.  This yields unjust rates in at least two separate ways. First, ratepayers are procuring extra capacity that they don’t need. Second, the auction clearing price is likely to be higher than it should be because the demand side of the equation is improperly exaggerated. So it is a double whammy: procuring too much of commodity and at a price that is artificially inflated.

FERC discusses this issue in paragraph 7, page 3, of its Order:

NEPOOL states that it does not support the ICR value because NEPOOL believes the ICR value should be reduced to account for distributed generation, especially solar photovoltaic resources, that is forecasted to be available during the 2018/2019 Capacity Commitment Period. According to NEPOOL, some participants contend that failure to reflect the amount of solar photovoltaic capacity in the ICR calculation will lead to over-procurement of capacity in the FCA.

Although the FERC Order does accept the ISO’s ICR filing for this auction, the Commission also tells the ISO to clean up its act before the ICR filing for the next auction, FCA-10. This is an important victory for renewable energy (and for common sense). The language I am referring to appears in paragraph 20, page 8, of the January 2 FERC Order:

[W]hile we are accepting ISO-NE’s proposed values for FCA 9, we expect ISO-NE to fully explore the incorporation of distributed generation into the ICR calculation in the stakeholder process. We expect ISO-NE to do this on a schedule that will allow these factors to be reflected, if determined appropriate, in the ICR calculation for FCA 10.

Over the coming year, CLF will use this language to push the ISO to correct its huge mistake for its next ICR filing in November 2015, for the next auction, FCA-10, to be held in February 2016. If the ISO does not listen to CLF – and to the overwhelming majority of NEPOOL members – on this issue, there is the very real possibility that next time FERC will reject the ISO’s flawed ICR calculation.

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