PJM to Hike Penalties, Incentives to Improve Winter Reliability
RTO Insider | August 7, 2014
Winter is Coming
PJM will increase performance penalties and incentives and seek ways to incorporate firm gas transportation in energy prices under an initiative announced last week to reduce generator outage rates.
PJM CEO Terry Boston announced the initiative, which he said resulted from a three-day meeting of the Board of Managers and discussions with present and former leaders of the Members Committee and stakeholder sectors.
The action was prompted by January’s extreme cold, when as much as 22% of PJM’s generation suffered forced outages, three times the normal winter rate.
“We would have to interrupt load if this happened in [future] winters,” Boston told the Markets and Reliability Committee Thursday, noting that the RTO will lose about 8,500 MW of generation to retirements by the winter of 2015/16. “We feel [changing capacity rules] has to be one of our highest priorities.”
Officials said the changes may increase capacity costs but should also reduce volatility during tight supply/demand conditions.
Redefinition of Capacity
“You should think of this as a holistic redefinition of what capacity is,” said Andy Ott, executive vice president for markets.
Members’ initial response to the initiative — which PJM said would be conducted under expedited procedures outside the normal stakeholder process — was muted.
David “Scarp” Scarpignato of Direct Energy questioned whether PJM would bring proposed changes to “advisory” votes before the MRC or Members Committee.
Gregory Carmean, executive director of the Organization of PJM States (OPSI), expressed concern that additional costs would be largely for winter performance while capacity cost allocation is based on summer loads.
Carl Johnson, representing the PJM Public Power Coalition, expressed misgivings over the initiative during a later MRC discussion regarding the Triennial Review of capacity auction parameters.
Johnson said stakeholders haven’t received enough information on the cost impact of the parameter changes, which include a potential increase in the Installed Reserve Margin. Referring to PJM’s plans to “redefine” capacity Johnson said, “When we don’t understand what we’re buying when we buy capacity, to say we’re going to be buying more of it, we cannot support.”
The Consumer Advocates of PJM States discussed the initiative yesterday and was expected to issue a statement later this week.
A key part of the new definition will be fuel security, meaning incentives are likely to encourage nuclear generators, dual-fuel units and firm gas contracts.
“At 20 mph [the speed at which gas flows], there’s not a lot of difference between just-in-time delivery and too dang late,” Boston said.
He also referred to two coal plants that were unable to operate in January because they lacked natural gas needed to start up. “Twenty thousand dollars’ worth of fuel oil could have brought those units up,” Boston said. “I would pay that now.”
More Flexible Operations
Officials also will be seeking to reverse a trend toward less flexible unit operating parameters. In a 23-page white paper issued Friday, PJM said unit flexibility has dropped as a result of staffing reductions and other cost cuts.
Ott said limits on unit flexibility must be a function of operational limits, not financial concerns. “We’ve seen units with three starts per day reduced to one; units with very short minimum run times became very long minimum run times,” he said.
The effort will also seek to boost operations and maintenance spending to improve generator availability on “low probability peak events” such as January’s polar vortex or last September’s unexpected heat wave.
“Generation owners may choose to cut O&M costs or choose not to make investments that enhance availability as a means to manage costs,” the report noted. “In making such a decision, the generation owner has implicitly or explicitly made a calculation that the benefits of such measures [increased net revenues] do not cover these ‘additional’ costs.”
Generator owners also have complained that there is no way to reflect such costs in supply offers.
“Competitive pressure to clear in the RPM capacity market may push generation owners to not make these investments if they feel other competitors are taking a similar strategy due to the risk of pricing themselves out of the market,” the report said.
PJM said current penalties for capacity resources that are unavailable during the 500 “peak” hours per year are insufficient.
The Tariff defines summer peak hours as Hour Ending 1500 to HE 1900 on non-holiday weekdays from June through August. Winter peak hours are HE 800 to HE 900 and HE 1900 to HE 2000 on non-holiday weekdays in January and February.
Penalties are assessed only if the forced outage rate during peak hours (EFORp) is more than the five-year average forced outage rate (EFORd5) of the resource.
Generators are often able to avoid even these penalties because the Tariff forgives outages related to a lack of gas as “Out of Management Control (OMC).”
“The penalties for being unavailable during the pre-defined peak hours … provides no incentive to make investments in O&M or infrastructure to enhance availability since there is little risk of incurring a capacity market penalty for being unavailable during reliability critical events,” the report said.
The current structure “provides an incentive for generation owners to hide the real cause behind an outage, or to shift the cause of an outage to a third party such as a gas pipeline” and claim it as OMC, the report said. However fuel delivery contracts and installation of dual-fuel capacity “are business decisions well within the control of the generation owner.”
EIA: Marcellus accounts for 40% of US shale gas production
Oil & Gas Journal | August 7, 2014
Natural gas production from the Marcellus shale has surpassed 15 bcfd through July and now represents 40% of US shale gas production, making it the largest producing shale gas basin in the country, according to the US Energy Information Administration’s Drilling Productivity Report.
While the region’s rig count has leveled off at around 100 rigs over the past 10 months, improvements in drilling productivity have enabled operators to more efficiently support new wells.
EIA expects wells coming online in August to add more than 600 MMcfd to existing production, more than offsetting a drop in production due to existing well decline rates, thus increasing the production rate by 247 MMcfd.
Marcellus production in recent years has shot up to record levels after accounting for just 2 bcfd in 2010, resulting in record gas storage injections, multiple pipeline expansion projects to remedy bottlenecks, and stabilized or decreased prices (OGJ Online, Apr. 25, 2014).
EIA points out that gas prices in the US Northeast, such as the Dominion South trading point in southwestern Pennsylvania, have increasingly been below the Henry Hub price, in part because of more access to Marcellus gas.
According to a report released by Moody’s in April, however, Marcellus producers are expected to benefit more than producers elsewhere in the US, even if prices were to decline to 2012 levels, because of rapid technological advancements, large producing wells in the northeast section conveniently located near major markets, and increased capital poured into the NGL-rich southwestern section (OGJ Online, Apr. 1, 2014).
Production in the region is now on pace to be enough to meet the combined winter demand of Pennsylvania, West Virginia, New York, New Jersey, Delaware, Maryland, and Virginia, EIA says.
Natural Gas and Oil Market Update
Natural Gas Futures Pare Gains After Supply Report
Investing.com | August 7, 2014
Natural Gas futures lost some steam early Thursday after the Energy Information Administration reported an increase in U.S. supplies in line with Wall Street expectations. Natural-gas supplies rose by 82 billion cubic feet in the week ended Aug. 4, the EIA reported. Analysts polled by Platts had expected an increase between 81 bcf and 85 bcf. Natural gas for September delivery added 3 cents, or 1%, to $3.95 per million British thermal units. The contract traded at $3.97 per million Btu before the report.
Oil Rises From 6-Month Low on Speculation Drop Overdone
Bloomberg | August 7, 2014
West Texas Intermediate oil traded near a six-month low on speculation that falling U.S. refinery utilization rates will reduce crude demand.
WTI for September delivery advanced 2 cents to $96.94 a barrel at 10:19 a.m. on the New York Mercantile Exchange. It touched $96.55 earlier, the lowest intraday price since Feb. 4. The volume of all futures traded was 36 percent above the 100-day average. Prices are down 1.5 percent this year.
Brent for September settlement climbed 44 cents, or 0.4 percent, to $105.03 a barrel on the London-based ICE Futures Europe exchange. The European benchmark crude traded at a $8.09 premium to WTI, after closing at $7.67 yesterday.
EIA - Weekly Natural Gas Storage Report
Working gas in storage was 2,389 Bcf as of Friday, August 1, 2014, according to EIA estimates. This represents a net increase of 82 Bcf from the previous week. Stocks were 538 Bcf less than last year at this time and 608 Bcf below the 5-year average of 2,997 Bcf. In the East Region, stocks were 284 Bcf below the 5-year average following net injections of 62 Bcf. Stocks in the Producing Region were 252 Bcf below the 5-year average of 1,035 Bcf after a net injection of 14 Bcf. Stocks in the West Region were 73 Bcf below the 5-year average after a net addition of 6 Bcf. At 2,389 Bcf, total working gas is below the 5-year historical range.
NYMEX Natural Gas Week-to-Week Price Change
Natural Gas Futures - Five Year Price ($ per mmBtu)
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