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In This Issue

On a Mission for Transmission: Has New England Spent Too Much on Electricity Grid Infrastructure?

Power in play: New England Losing Generators, So How Could Burrillville plant Not Be Needed?

Natural Gas and Oil Market Update

EIA - Weekly Natural Gas Storage Report

NYMEX Natural Gas Week-to-Week Price Change

Natural Gas Futures - Five Year Price

Tables

NOAA 6 to 10 Day Outlook
weatherweather
Color indicates the probability of forecasted temperatures being above or below a historical average for the period.

 

Market Overviews

On a Mission for Transmission: Has New England Spent Too Much on Electricity Grid Infrastructure?

WNPR | June 16, 2016

There’s a charge in your electricity bill that’s been rising steadily over the last decade.

This is a look at why New Englanders pay more for energy transmission than almost anyone else in the country, and at some efforts to change that. 

New England electricity users collectively share the cost of building and maintaining a transmission system that we can rely on to safely move bulk, high-voltage electricity around the region — and keep the lights on. In Maine, consumers pay about 8.5% of that cost. That’s in proportion to how much of the region’s electricity Maine uses.

“We’re paying for a grid that’s reliable and works. And it may not feel that way during ice-storms. But the grid that we have in New England and the United states is the envy of the world in terms of reliability. That’s real. We paid for that. There’s a cost associated with that,” says Tim Schneider, the state’s public advocate.

His job is protecting consumers’ interests when regulators decide what grid investments are necessary and justifiable. Schneider says reliability is essential. But here in New England, he adds, consumers may pay more than is necessary — and more than consumers do in other regions of the country.

“We have built a lot of transmission in New England,” he says. “And it’s really costly. There doesn’t appear to be a lot of cost controls. There’s not a lot of transparency around what’s driving those costs.”

Over the last 15 years, major transmission upgrades in New England have more than tripled the portion of Central Maine Power bills that covers those costs. In 2002, it was less than four dollars out of a typical monthly bill; by 2014, it was more than $12.

And a recent report found that between 2010 and 2014, the transmission component of wholesale power prices in New England were anywhere from twice to three times as much as in most of the rest of the country. There’s some history behind that imbalance. Some of it goes back to Depression-era federal investment in transmission and generation in the south and west. Some goes back to investments made in New England after the northeast blackout of 1965. And some is more recent.

“We had the blackout of 2003, says Eric Stinneford, a top executive at Avangrid, CMP’s parent company.

He says after that grid failure the federal government created a rigorous and mandatory set of standards for planning reliability investments. And it gave utilities a big incentive to do it — a boost in the return on equity they could earn on transmission investments — to a total of more than 11%. Since then in New England, there’s been almost $7 billion worth of new grid investments. Other regions, Stinneford says, have spent proportionately less.

“I think it’s a fair question why haven’t other regions seen something similar, and a lot of that has to do with a variety of factors, some of which is geography where in New England we’ve seen a shift of the generation resources getting further away from the population centers where the generation is being consumer,” says Stinneford. “I don’t think that is the case everywhere else.”

Public Advocate Schneider says, though, that some of the other factors for the imbalance can be addressed. First of all, there’s that nice return on equity the utilities can earn. He and other players have argued to the federal government that earning threshold should be reduced, and in a recent decision, it did so — shaving it to 10.6%. A new decision is expected soon in a case that seeks to get the number below 9%.

Other efforts focus on predicting just how much electricity the region will use in the future, a foundation for regional decisions on what’s needed to ensure reliability. New England grid regulators recently decided — at the urging of states and environmentalists — to factor in the effects of state policies that reduce electricity demand. Theodore Paradise is a counselor at ISO-New England, which administers the regional grid.

“Once we factor in that energy efficiency spending by the states and the photo-voltaic subsidies, things like that, we see that that energy curve is really flattening out and that has a direct impact in what kind of transmission we need and where we need it how much we need and what kind of capacity we need and where we need it, and the cost of that,” says Paradise.

There’s more work being done too — to more accurately predict just what kinds of emergency events to plan for, to put transmission developers, rather than consumers, on the hook when a project goes way over cost, or to get more transparency in federal decisions on just what utilities will be allowed to charge for transmission.

And there’s something else to consider, beyond reliability. This region’s transmission investments have also improved access to newer, lower-cost electric generators and allowed older, costlier generators to be retired. That drives down the price of electricity itself, which is a bigger part of our power bills than transmission. Players on all sides of the issue say that going forward, the energy-cost pendulum just might swing New England’s way, as states that have invested less in transmission are forced to play a bit of catch up.

Read More:
http://wnpr.org/post/mission-transmission-has-new-england-spent-too-much-electricity-grid-infrastructure#stream/0

Power in play: New England Losing Generators, So How Could Burrillville plant Not Be Needed?

Providence Journal | June 16, 2016

Is New England facing an energy shortage in the next few years as aging power plants around the region close down?

The answer to that question could go a long way to determining whether the Rhode Island Energy Facility Siting Board approves a proposal to build a 1,000-megawatt natural gas-fired power plant in Burrillville that would be among the largest electric generators in New England.

Invenergy, the Chicago developer behind the $700-million project, and its backers in local construction unions and state business groups, say the answer is a definite yes. As Exhibit A in their case, they point to an analysis by Independent System Operator New England, the nonprofit that manages the regional electric grid. ISO-NE assessed the fleet of power plants in the six states and found that nearly a third of the grid's generating capacity will have closed or be at risk of closure by 2020.

"It may not be reflected now, but I can't imagine there isn't going to be a shortage," said Douglas Gablinske, director of The Energy Council of Rhode Island, a group that represents some of the largest power users in the state.

But on the other side of the debate is the Conservation Law Foundation and other environmental groups that oppose the continued use of fossil fuels for power generation. They argue just as vigorously that the answer is no. They hold up as evidence the results of the most recent auction to secure future power supply for the region. Not only was the purchase price, known as the clearing price, lower than in recent years, but ISO-NE was able to lock in a surplus of generating capacity.

"Even without Invenergy, there is an excess of supply," said Jerry Elmer, staff attorney for the CLF.

Over the last decade or so, a glut of cheap natural gas from shale fields in Pennsylvania and beyond has flooded energy markets across the nation. In New England, the new supplies of gas are driving a transformation of the region's energy fleet, pushing out of business many of the coal- or oil-fired power plants that had been the bedrock of the grid.

Four major plants closed in 2013 and 2014 — Salem Harbor Station and Mount Tom Power Station, both coal-burners in Massachusetts, oil-burning Norwalk Harbor Station in Connecticut and Vermont Yankee Nuclear Power Plant.

And two more big power plants in Massachusetts are set to close soon. Brayton Point Power Station, the region's largest coal-burning plant, will shut down next year, unable to compete with the lower price of gas. Pilgrim Nuclear Power Station will close its doors in 2019 because of the rising cost of safety upgrades. Add those two facilities to the four that already closed and the loss in generating capacity totals 4,200 megawatts or so.

But ISO-NE has also categorized a bunch of other plants around the region "at risk of retirement" because they burn coal or oil. The list includes three of the 10 largest power plants in New Hampshire, four of the 10 largest plants in Connecticut, two of the 10 largest in Massachusetts and the largest plant in Maine. Many have generating units from the 1960s and three date to the '50s. The plants add up to another 6,000 megawatts of capacity, according to ISO-NE's 2012 study.

It's against that backdrop that Invenergy came forward last year with its plan to build what it's calling the Clear River Energy Center in eastern Burrillville, arguing that the plant is necessary to make up for the projected shortfall.

"The announced and unannounced retirements and the forecast for further electricity demands of customers make it irresponsible to not take action," John Niland, director of business development for Invenergy, said in a recent filing with the Rhode Island Public Utilities Commission.

Gablinske, of TEC-RI, whose membership includes such companies as Hasbro and Toray Plastics, said the plant would act as something equivalent to an insurance policy.

"A reliable power supply," he said. "That's what's guaranteed with this plant."

He argued that it would be irresponsible not to develop the project with so much uncertainty hanging over the region's electric grid. Because it takes years to develop energy projects, it's wiser to approve something now before a shortage arises, he said.

But new sources of renewable energy are coming on line and energy efficiency is tempering demand in New England. Elmer, of the CLF, cited the Feb. 8 ISO-NE forward capacity auction as proof that those and other efforts are filling the region's needs.

The auction anticipates energy needs three years ahead. The most recent auction found more than adequate capacity for the 2019-2020 supply year from existing and planned generators — after both Brayton Point and Pilgrim are to close.

"The fact is that the auction accounts for all the plants that will close and all of the new resources that are coming in," he said.

He also pointed to Invenergy having sold only 485 megawatts of generating capacity in the auction — the output of only one of the two turbines at the plant, which would begin operating in 2019.

Elmer's argument, insofar as it concerns the significance of February's forward capacity market auction, was echoed by Paul Roberti, a member of the PUC who served a year beyond his term and is set to be formally replaced this week by former state energy commissioner Marion Gold.

"Invenergy cleared half of its capacity. From 30,000 feet you could argue that the market, and whether or not a resource clears, is an indication of need," said Roberti.

The need for Invenergy, and other relevant power-market issues, will be considered by the PUC over the coming weeks as it draws up an advisory opinion for the Energy Facility Siting Board that will be included in the board's consideration of the proposal.

In the end, any judgment on a need for the Invenergy plant may not come down strictly to a question about an energy shortage in New England. The regional grid, after all, is connected to New York and Quebec, which supplies large amounts of hydropower. On peak demand days, power can be imported -- or old, seldom-used generators can be fired up -- to remedy any shortfall.

The question may have more to do with the types of power the region will use. The CLF and other groups that prioritize a plan to address climate change want to see the immediate development of more renewable power sources, such as wind farms and solar arrays, and say New England is already too reliant on natural gas, which provides about half the region's energy supply.

TEC-RI supports a more gradual move towards renewables. In the meantime, the group says, the Clear River Energy Center, which Invenergy argues will be the most efficient fossil fuel generator of electricity in New England, is needed to replace the dirtiest, oldest and least-efficient facilities.

Roberti, the former PUC member, said everyone is trying to figure out the right energy mix for New England, one that incorporates cleaner sources while ensuring reliability and keeping a rein on prices, already among the highest in the nation.

"There's no clear answer," he said. "Fundamentally, the resource decisions can and are made by the regional markets that we have agreed to employ."

Read More:
http://www.providencejournal.com/news/20160612/power-in-play-new-england-losing-generators-so-how-could-burrillville-plant-not-be-needed

Natural Gas and Oil Market Update

Arrow

Oil Futures Settle At 5-Week Low On Brexit Worries

Bloomberg | June 16, 2016

Oil futures settled lower for a sixth straight session Thursday—their longest losing streak since February—and marked their lowest settlement in about five weeks.

Market jitters over the looming U.K. referendum on whether to leave the European Union, a so-called Brexit, fueled concerns about a potential slowdown in
energy demand and a recent rise in the number of U.S. rigs drilling for oil pointed to a possible uptick in crude production levels.

“With the turmoil in global markets, we will see a pullback in confidence leading to a potential pullback in energy demand,” said Phil Flynn, senior market analyst
at Price Futures Group.

  Arrow

Natural Gas Futures Extend Losses After Bearish U.S. Storage Data

Investing.com | June 16, 2016

U.S. natural gas futures added to losses in North America trade on Thursday, after data showed that natural gas supplies in storage in the U.S. rose more than expected last week.

Natural gas for delivery in July on the New York Mercantile Exchange shed 2.0 cent, or 0.77%, to trade at $2.575 per million British thermal units by 14:55GMT, or 10:55AM

ET. Prices were at around $2.593 prior to the release of the supply data.

The U.S. Energy Information Administration said in its weekly report that natural gas storage in the U.S. in the week ended June 10 rose by 69 billion cubic feet, above forecasts for an increase of 64 billion.

EIA - Weekly Natural Gas Storage Report

EIA - Weekly Natural Gas Storage Report

Summary
Working gas in storage was 3,041 Bcf as of Friday, June 10, 2016, according to EIA estimates. This represents a net increase of 69 Bcf from the previous week. Stocks were 633 Bcf higher than last year at this time and 704 Bcf above the five-year average of 2,337 Bcf. At 3,041 Bcf, total working gas is above the five-year historical range.

NYMEX Natural Gas Week-to-Week Price Change NYMEX Natural Gas Week-to-Week Price Change

Natural Gas Futures - Five Year Price ($ per mmBtu)

NYMEX Natural Gas Week-to-Week Price Change - Five Yearly Snapshot

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