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In This Issue

New England Pays Most in Contiguous U.S. for Electricity

Center of the Storm: PJM CEO Andy Ott on Power Market Reforms for Turbulent Times

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


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


New England Pays Most in Contiguous U.S. for Electricity

Go Local | July 13, 2017

New England pays more for electricity than any other region in the United States, according to a new white paper released by Consumer Energy Alliance (CEA).

According to the U.S. Energy Information Administration (EIA), New Englanders paid, on average, 151 percent more than the national average between April 2015 and March 2017, with consumers in Massachusetts paying 154 percent more than the national average and residents in Connecticut paying 161 percent more. 

"Keeping energy costs low is a priority for New England families, small businesses, and manufacturing, for fuel, home heating, and cooling, plus transportation – and that’s just not happening. As natural gas usage grows, and other commonly-used resources go offline, suppliers are even more reliant on pipelines and other energy delivery systems to safely transport resources and power the region. But unless policymakers approve more infrastructure proposals, costs will continue to escalate while the region struggles to keep pace with intensifying demand,” said David Holt, President of Consumer Energy Alliance (CEA).  

All seven New England states are in the top 10 nationally in terms of highest rates, and only Alaska and Hawaii, geographically isolated from many affordable electricity resources, pay more. 

Reasons Why New Englanders Pay More

According to ISO New England and the Massachusetts Office of Energy and Environmental Affairs, the following reasons are why New England pays so much for electricity:

  • New England imports about 15 percent of its electricity from other regions.
  • Almost half of its electricity comes from natural gas – a figure that continues to grow.
  • The region lacks critical energy delivery infrastructure, which leads to bottlenecks, more strain on existing infrastructure and mounting challenges in delivering affordable energy.
  • Coal, oil, nuclear and hydropower supplies are dwindling.
  • About 4,200 megawatts, or about 15 percent, of New England’s generating capacity will go offline by 2020 – enough to power 4.2 million homes.
  • Another 5,500 megawatts are at risk for retirement.
  • Uncertainty surrounds 3,300 megawatts of generation from nuclear plants (through retirements).

Infrastructure Proposals

The Consumer Energy Alliance says that one solution is more infrastructure proposals.

"Polls have shown that a majority of voters in these states support safely moving oil, natural gas, and transportation fuels via the approval and construction of more pipelines. And the region’s independent grid regulator who has repeatedly stressed that a lack of pipeline infrastructure on high energy demand days not only puts the grid’s reliability at greater risk but also increases pressure on spot market prices could not agree with those voters more,” said Holt.

According to CEA, data shows that denying infrastructure proposals will cost New England and neighboring states over 78,000 jobs and lower the region’s gross domestic product by $7.6 billion by 2020, adversely impacting at least 7 million local families and seniors living in poverty.

Alternatively, adding pipeline energy delivery infrastructure would collectively save ratepayers between $2.1 billion and $2.8 billion annually. 

Read More:

Center of the Storm: PJM CEO Andy Ott on Power Market Reforms for Turbulent Times

Ott spoke to Utility Dive about leading PJM's push to reform its operations and pricing for the new energy economy

The PJM Interconnection, the nation's largest electricity market, is ground zero for many of the most dramatic changes rocking the power sector. 

PJM spans 13 states and the District of Columbia, comprising more than 170 GW of generation capacity. Regional transmission organizations have been around 90 years, but PJM’s current role dates back to 1996, when it became the first deregulated power market in the United States.

Back then, operations were relatively simple — a largely coal and nuclear generation fleet with a growing number of gas generators operating on a one-way grid.

More than 20 years later, that fuel mix looks almost unrecognizable. The shale gas boom of the last decade has helped gas-fired plants approach 50% of PJM’s installed capacity. Steady price declines and federal subsidies also encouraged the siting of gigawatts of wind generation, and the region boasts the nation’s largest demand response market.

Those changes have not come without casualties. Cheap gas, stagnating load growth and subsidized renewables have pushed power market prices to historic lows, making it difficult for baseload coal and nuclear plants to compete.

The market changes prompted some generators to push for state subsidies to keep operating, including coal interests in Ohio and nuclear operators there and in Illinois, Pennsylvania and New Jersey. But some stakeholders are worried, with PJM’s market monitor warning the subsidies could “threaten the foundations” of the market.

As PJM’s CEO, Andy Ott is at the center of the storm, overseeing the market's operations at a time of unprecedented change. In an interview at the Edison Electric Institute's conference last month, he told Utility Dive that despite the upheavals, PJM’s last few years have been largely successful.

“Certainly the competitive markets are working and getting investments,” Ott said. “We're seeing reliability at low price, about 30,000 megawatts of new gas combined cycle over the past six years. So, a fairly significant success story.”

But while Ott says near-term reliability is secure, PJM is assessing a number of trends that are causing concern among its stakeholders, including system resiliency, nuclear subsidies and negative pricing offers. The RTO staff has published a raft of papers in recent months outlining the issues, which Ott said will help PJM prepare to deal with any future market or policy shifts.

“The concern I have is not necessarily for the health of the market because we will take care of that,” he said. “We will do the appropriate design changes we need to make the market continues to operate effectively.”


While coal generation is on the wane nationwide, the shift toward gas in PJM has been particularly pronounced. Between 2011 and 2020, the market monitor estimates 28.4 GW of generation will retire, including more than 20 GW of coal.

Those coal retirements, along with high-profile nuclear plant closings, have raised questions among some stakeholders about the resiliency of PJM’s system. During the Polar Vortex of 2014, high gas demand and pipeline constraints rendered some gas plants inoperable. Coal operators argue their plants are needed to ensure reliability in such situations, despite the fact that a few had to shut down during the Polar Vortex due to frozen coal piles.

The argument has been picked up by the Trump administration as well, with EPA Administrator Scott Pruitt repeatedly saying that plants with “solid hydrocarbons onsite” are needed to preserve reliability.

Ott says those issues are just some of the complicating factors in preserving reliability in the PJM region.

"We used to worry about when we'd lose a transmission line or a transformer or a generator,” he said. “Now it's those plus sabotage, terrorism, cybersecurity threats and the concern is, are operational risks in the power sector being accounted for in day-to-day operations?”

Addressing those risks is what Ott calls the “notion of resilience,” which PJM staff focused on in a March report outlining the reliability implications of the changing resource mix.

The report found that PJM’s system could continue to operate with a portfolio of up to 86% natural gas, although fuel deliverability impacts were not fully captured in the analysis. Similarly, the report found PJM could operate with unprecedented levels of renewable energy penetration, but only with a “portfolio of other resources that provides a sufficient amount of reliability services.”

Moving forward, Ott said PJM will continue to dialogue with stakeholders on the appropriate pricing mechanisms for reliability and resiliency. Last month, it rolled out a resiliency roadmap outlining how it will engage the issue over the next year and beyond.

“Legitimate questions are being asked,” Ott said. “So that whole area of fuel security resilience — are we really looking into risks with a lens that is appropriate given the circumstances we are in today, which is different than where we were before, and are we pricing appropriately?”

Nuclear subsidies and carbon pricing

The same market forces sparking the resiliency discussion — cheap gas, low load growth and increasing renewables — are also working to push a number of nuclear generators offline.

Nuclear generators argue the PJM market does not fully value their contributions to climate change mitigation and resiliency, instead turning to states for “around-market” subsidies to keep operating. Illinois and New York, which has its own ISO, enacted zero-emission credit programs for nuclear plants last year, inspiring a rash of imitators in other states.

“I think it's a legitimate question,” Ott said. “The way I describe it is people are saying, 'Fast forward ten years and if these plants actually go out on economics, will we turn around and look back with regret, wishing we had done something?'”

That “something,” Ott said, is a “reality check” for the industry. “Do we value clean resources? We don’t have a carbon market, but should we? The talk about pricing those attributes is becoming more urgent.”

PJM cannot institute a price on carbon itself, but in May it issued a paper for FERC’s technical conference on generation subsidies outlining how it could integrate a carbon price if states chose to do so. That paper was updated with a new version last month.

In order to make a carbon price work, PJM would need to measure energy transfers between states with and without carbon prices, track carbon emissions over the states, and adjust power market prices accordingly.

Rather than state subsidies for individual resources, Ott said a carbon price presents a more efficient way to keep zero-carbon plants online. But PJM can’t do it alone — the states would have to pass carbon price policies individually.

“If we truly as a society value zero-carbon resources, the only way the market is going to look consistent is if we are able to value those inside the market,” he said. “Otherwise, people will complain that the market's not pricing the resources they value.”

Absent that solution, some stakeholders are concerned that the state nuclear subsidies could prove detrimental, depressing capacity market prices so much that the entire construct unravels.

Ott distanced himself from those claims, saying the RTO will ensure the markets continue to operate. His role, he said, is to point to the best solution for the market.

“Concern is a strong word,” he said. “The fact that the subsidy discussion is going on leaves us to say, 'Look, while you're having that discussion, realize there's a more efficient one.'”

Price formation and equity

Even if states give up their nuclear subsidies, “around-market” generation mechanisms will still exist in PJM. A number of states have renewable portfolio standards, which mandate a certain level of wind and solar procurements, and wind still benefits from the federal production tax credit, which pays about $23/MWh for the generation.

These around-market mechanisms for renewables create similar issues to the nuclear subsidies by bringing down wholesale power prices. But in the case of wind, the PTC means that it can sometimes push prices into negative territory.

When the RTO needs to reduce the amount of wind generation on the system — typically during low-demand hours at night — it sends a negative pricing signal to the generators, Ott explained. Wind can continue to operate in that negative pricing environment due to the PTC, but all the other plants in the stack also receive those negative prices, cutting into their revenues.

“Is that the right answer?” Ott asked. “Is there a better way to ration that small amount of megawatts, and therefore not discount the value of these other assets we need in service?”

PJM addressed those questions in a June white paper on price formation and valuing generation flexibility. Its goal, the RTO said at the time, is to initiate dialogue with federal energy regulators on how to reform pricing techniques to mitigate the impact of negative offers.

“In a nutshell, this is something that needs to be discussed at a federal level,” Ott said, “and that’s what I said at [the FERC technical conference] — are we so sure that our energy price formation is correct?”

Negative pricing typically affects day-to-day energy market prices, but PJM is also addressing subsidies’ impacts on the longer-term capacity market, which lines up generation years into the future.

The concern is that subsidized nuclear and renewables will depress prices in capacity markets so much that unsubsidized plants — mostly gas generators — will not be able to cover their costs and will therefore retire prematurely.

While Ott stressed that reliability is not under threat from this phenomenon in the near term, the RTO is looking at ways to mitigate the effects. In May, it presented a proposal for a two-part capacity auction at the FERC technical conference, which was updated in June. ISO-New England offered a similar plan as well.

The new auctions would separate the subsidized resources from unsubsidized ones. After subsidized resources clear the market, the grid operator would recalculate prices for unsubsidized plants by "[r]emoving offers submitted by subsidized units ... and replacing those offers with reference price offers reflecting what would be a competitive offer from a unit of that type and vintage."

“If we have a competitive state where they take a specific targeted action for a resource, then effectively, for the purpose of setting a competitive capacity price, we essentially remove that resource from the ability to set the competitive price,” Ott said. “We match that resource up within the same state, set that aside and then do the pricing.”

In an overview of the market reform papers, PJM authors say they are not a direct response to nuclear and renewable subsidies, but rather an examination of whether rapid changes in the sector "require re-examination of PJM rules that define when and under what circumstances a generator is eligible to set marginal prices."

The overview hypothesizes that the “correct” clearing market price could be “understated” by rules that disqualify inflexible generation from setting clearing prices. If that is correct, “the pricing problem does not arise because subsidies have distorted prices. Rather, state programs, to some extent, may be a response to organic deficiencies in market design.”

Some energy analysts are skeptical of the changes, however. Writing in Utility Dive, Robbie Orvis and Eric Gimon of Energy Innovation argue that the two-part capacity auction proposal could actually result in even further depressed prices while promoting the extended use of carbon-emitting generation.

“In PJM, market operators use a demand curve when choosing the amount of resources procured. Lower resource offer prices mean more capacity is procured,” they wrote. “However, because units know their prices will be inflated in the second stage of the auction when subsidies are added in, they are likely to lower their offer prices, resulting in even more capacity being procured.”

Ott said that the two-part proposal is not meant to benefit gas generators or any other particular resource, but instead ensure pricing equity across the RTO.

“The key is the cost shifts that occur. If one state does this type of activity, it shifts costs potentially to another state, and that’s the reality,” he said. “If these activities occur then we have to take action to do some form of mitigation or some form of changing the way we present those resources to the market.”

Ott expects the role of preserving market equity to be key in the years to come.

“From a market perspective, making sure the market remains competitive, free from undue influence and again is equitable for everyone — that is our mandate,” he said

Read More:

Natural Gas and Oil Market Update


Natural Gas Price Inches Higher Following Storage Report

24/7 Wall St | July 13, 2017

The U.S. Energy Information Administration (EIA) reported Thursday morning that U.S. natural gas stocks increased by 57 billion cubic feet for the week ending June 30. Analysts surveyed by S&P Global Platts were expecting a storage injection of between 43 billion and 64 billion cubic feet.

The five-year average for the week is an injection of 72 billion cubic feet, and last year’s storage injection for the week totaled 61 billion cubic feet. Natural gas inventories rose by 72 billion cubic feet in the week ending June 30.


Oil Notches Fourth Session Rise To End At A Nearly Two-Week High

MarketWatch | July 13, 2017

Oil tallied a fourth session of gains on Thursday, settling at a nearly two-week high, with prices finding support from the largest weekly decline for U.S. crude inventories in 10 months and a forecast for stronger growth in demand this year.

Traders, however, remained wary of recent reports revealing further gains in global production, particularly after the International Energy Agency said global oil supply rose in June as producers “opened the taps.”

EIA - Weekly Natural Gas Storage Report

EIA - Weekly Natural Gas Storage Report

Working gas in storage was 2,945 Bcf as of Friday, July 7, 2017, according to EIA estimates. This represents a net increase of 57 Bcf from the previous week. Stocks were 289 Bcf less than last year at this time and 172 Bcf above the five-year average of 2,773 Bcf. At 2,945 Bcf, total working gas is within 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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